ML13081A762

Entergy'S Proposed Findings of Fact and Conclusions of Law for Contention NYS-5 (Buried Piping)

ML13081A762
Person / Time
Site:	Indian Point
Issue date:	03/22/2013
From:	Bessette P, Dennis W, Glew W, O'Neil M, Sutton K Entergy Nuclear Operations, Morgan, Morgan, Lewis & Bockius, LLP, Entergy Services
To:	Atomic Safety and Licensing Board Panel
SECY RAS
References
RAS 24277, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01
Download: ML13081A762 (126)

Text

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD

)

In the Matter of ) Docket Nos. 50-247-LR and

) 50-286-LR ENTERGY NUCLEAR OPERATIONS, INC. )

) March 22, 2013 (Indian Point Nuclear Generating Units 2 and 3) )

)

ENTERGYS PROPOSED FINDINGS OF FACT AND CONCLUSIONS OF LAW FOR CONTENTION NYS-5 (BURIED PIPING)

William B. Glew, Jr., Esq. Kathryn M. Sutton, Esq.

William C. Dennis, Esq. Paul M. Bessette, Esq.

Entergy Nuclear Operations, Inc. MORGAN, LEWIS & BOCKIUS LLP 440 Hamilton Avenue 1111 Pennsylvania Avenue, N.W.

White Plains, NY 10601 Washington, D.C. 20004 Phone: (914) 272-3202 Phone: (202) 739-5738 Fax: (914) 272-3205 Fax: (202) 739-3001 E-mail: wglew@entergy.com E-mail: ksutton@morganlewis.com E-mail: wdennis@entergy.com E-mail: pbessette@morganlewis.com Martin J. ONeill, Esq.

MORGAN, LEWIS & BOCKIUS LLP 1000 Louisiana Street Suite 4000 Houston, TX 77002 Phone: (713) 890-5710 E-mail: martin.oneill@morganlewis.com COUNSEL FOR ENTERGY NUCLEAR OPERATIONS, INC.

TABLE OF CONTENTS Page I. INTRODUCTION ................................................................................................................... 1 II. PROCEDURAL HISTORY OF CONTENTION NYS-5 ....................................................... 3 A. LRA Submittal and Related Filing of Contention NYS-5 .......................................... 3 B. Subsequent Revisions to the BPTIP and the NRC Staffs Safety Evaluation ............. 8 C. New Yorks December 2011 Pre-filed Direct Testimony and the Parties January 2012 Joint Stipulation .................................................................................. 11 D. NRC Staffs and Entergys March 2012 Pre-filed Testimony .................................. 12 E. New Yorks June 2012 Pre-filed Rebuttal Testimony .............................................. 14 F. Other Prehearing Procedural Matters ........................................................................ 14

1. Revisions to the Parties Evidentiary Filings ................................................ 14

2. NRC Staff Motion in Limine to Exclude New York Rebuttal Exhibits........ 17

3. New Yorks August 2012 Motion for Cross-Examination ........................... 17 G. The December 10 and 11, 2012 Evidentiary Hearing ............................................... 23 III. APPLICABLE LEGAL AND REGULATORY STANDARDS .......................................... 24 A. Scope of License Renewal Review Under 10 C.F.R. Part 54 ................................... 24 B. Reasonable Assurance Standard................................................................................ 26 C. Demonstration of Reasonable Assurance Through Consistency with NUREG-1801 (the GALL Report) ........................................................................................... 27 D. Demonstration of Reasonable Assurance Through Licensee Commitments ............ 29 E. Burden of Proof ......................................................................................................... 31 IV. FACTUAL FINDINGS AND LEGAL CONCLUSIONS .................................................... 32 A. Witnesses and Evidence Presented ........................................................................... 32 B. Technical Background............................................................................................... 40 C. The IPEC BPTIP Is Consistent with the Applicable NUREG-1801 (GALL Report) Recommendations and Appropriately Documented in the LRA ................. 44

1. NUREG-1801 sets forth the NRC Staffs approved recommendations for aging management of in-scope buried and underground piping. ............ 44

2. The IPEC BPTIP is consistent with NUREG-1801, Rev. 1, AMP XI.M34. ......................................................................................................... 47

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TABLE OF CONTENTS (continued)

Page

3. Entergy substantially revised the IPEC BPTIP to reflect recent operating experience and to be consistent with the NRC Staffs key recommendations in NUREG-1801, Rev. 2, AMP XI.M41. ........................ 48

4. The IPEC BPTIP is adequately documented in the LRA.............................. 56 D. Relationship of the IPEC BPTIP to Entergys 10 C.F.R. Part 50 Underground Piping Program and Entergys Associated Fleet and Plant-Specific Procedures ................................................................................................................. 60 E. Enforceability of Entergy Procedures ....................................................................... 64 F. Technical Description of the IPEC BPTIP ................................................................ 68

1. Entergy has fully identified the buried and underground piping that is within the scope of license renewal and subject to the BPTIP, including piping that contains or may contain radioactive fluids. ................ 68

2. The BPTIP manages loss of material due to external corrosion of buried and underground piping to provide reasonable assurance that the associated systems can perform their license renewal intended safety functions. ............................................................................................ 73

3. The BPTIP appropriately relies on both preventive actions (coatings) and condition monitoring (inspections) to ensure that in-scope buried piping will continue to perform its intended function during the license renewal term. ..................................................................................... 76

4. The BPTIP provides sufficient details concerning planned inspections, acceptance criteria, and corrective actions. ............................... 79 G. Summary of Plant-Specific Operating Experience Relevant to the Condition of IPEC Buried Piping Coatings, Backfill, and Base Metal...................................... 86

1. The 2009 Condensate Storage Tank (CST) Return Line Leak ..................... 87

2. IPEC Direct and Indirect Inspections of Buried Piping Since 2009 ............. 90

3. Summary of IPEC Soil Testing Data ............................................................ 99

4. Board Conclusions Based on Review of Available IPEC Operating Experience ................................................................................................... 103 H. Current Use and Status of Cathodic Protection at the IPEC Site ............................ 103 I. New Yorks Claims that NRC and Industry Guidance Documents Require the Installation of Cathodic Protection Lack Merit ....................................................... 109 J. The BPTIP Is Consistent with the Key Recommendations Contained in NACE SP0169-2007 ............................................................................................... 114 V.

SUMMARY

FINDINGS OF FACT AND CONCLUSIONS OF LAW ............................ 116

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TABLE OF CONTENTS (continued)

Page VI. ORDER ............................................................................................................................... 120

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UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD

)

In the Matter of ) Docket Nos. 50-247-LR and

) 50-286-LR ENTERGY NUCLEAR OPERATIONS, INC. )

) March 22, 2013 (Indian Point Nuclear Generating Units 2 and 3) )

)

ENTERGYS PROPOSED FINDINGS OF FACT AND CONCLUSIONS OF LAW FOR CONTENTION NYS-5 (BURIED PIPING)

Pursuant to 10 C.F.R. § 2.1209, and the Atomic Safety and Licensing Boards (Board)

February 28, 2013 Order,1 Entergy Nuclear Operations, Inc. (Entergy) submits its Proposed Findings of Fact and Conclusions of Law (Proposed Findings of Fact and Conclusions) on New York State (New York) Contention 5 (NYS-5) in this license renewal proceeding for Indian Point Nuclear Generating Units 2 and 3 (IP2 and IP3). The Proposed Findings and Conclusions are based on the evidentiary record in this proceeding, and are submitted in the form of a proposed Partial Initial Decision by the Board. The Proposed Findings and Conclusions are set out in numbered paragraphs, with corresponding citations to the record of this proceeding.

I. INTRODUCTION

1. This Partial Initial Decision presents the Boards Findings of Fact and Conclusions of Law on Contention NYS-5, which alleges that Entergy lacks an adequate aging management program (AMP) for managing potential aging effects caused by external 1

Licensing Board Order (Granting Parties Joint Motion for Alteration of Filing Schedule) at 1 (Feb. 28, 2013)

(unpublished).

corrosion of in-scope buried piping that contains or may contain radioactive fluids at the Indian Point Energy Center (IPEC).2

2. For the reasons set forth below, the Board finds that Entergy has carried its burden of proof to demonstrate that its license renewal AMP, the Buried Piping and Tanks Inspection Program (BPTIP),3 as confirmed and modified through the U.S. Nuclear Regulatory Commission (NRC or Commission) Staffs (NRC Staff or Staff) comprehensive license renewal application (LRA) review process, provides reasonable assurance that Entergy will adequately manage the aging effects on buried piping at IPEC during the period of extended operation (PEO). As discussed below, the NRC Staffs review of the BPTIP and its associated findings are documented in its final Safety Evaluation Report (SER), as supplemented.4

3. The Board finds that the IPEC BPTIP (1) meets all applicable NRC requirements; (2) is consistent with current NRC and industry guidance on the aging management of buried piping; and (3) provides reasonable assurance that buried pipes addressed by the BPTIP, including those that contain or may contain radioactive fluids, will perform their intended functions during the PEO. The Board thus enters a ruling on the merits of contention NYS-5 in Entergys favor.

2 See Entergy Nuclear Operations, Inc. (Indian Point Nuclear Generating Units 2 and 3), LBP-08-13, 68 NRC 43, 81 (2008).

3 In this decision, we also refer to the IPEC Underground Piping and Tanks Inspection and Monitoring Program (UPTIMP), which is Entergys current program for managing buried and underground piping and tanks under 10 C.F.R. Part 50. We discuss the relationship between the BPTIP and UPTIMP in Section IV.D below.

4 See NUREG-1930, Vol. 1, Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3 at 3-13 to 3-18 (Nov. 2009) (SER) (NYS00326B); NUREG-1930, Supp. 1, Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3 at 3-1 to 3-5 (Aug. 2011) (SER Supp. 1) (NYS000160).

II. PROCEDURAL HISTORY OF CONTENTION NYS-5 A. LRA Submittal and Related Filing of Contention NYS-5

4. On April 23, 2007, Entergy applied to renew the IP2 and IP3 operating licenses for twenty years beyond their current expiration dates of September 28, 2013, and December 12, 2015, respectively.5 As relevant here, Section B.1.6 of the IPEC LRA described an AMP for buried piping at IPEC. As defined in NRC guidance, buried pipes are those in direct contact with soil or concrete (e.g., a wall penetration).6 In contrast, underground pipes are below grade but are contained within a tunnel or vault such that they are in contact with air and access for inspection is restricted.7

5. In its LRA, Entergy described the BPTIP as being consistent with the AMP described in Section XI.M34 of NUREG-1801, Vol. 1, Rev. 1, Generic Aging Lessons Learned (GALL) Report (Sept. 2005) (NUREG-1801, Rev. 1 or GALL Report, Rev. 1)

(NYS00146A-C).8 The original BPTIP, as described in the April 2007 LRA, relied on opportunistic inspections to manage the effects of external corrosion on the pressure-retaining capacity of buried steel piping and tanks.9 The program also specified one focused (direct 5

Letter from F. Dacimo, Site Vice President, Entergy, to NRC Document Control Desk (Apr. 23, 2007) available at ADAMS Accession No. ML071210512 (supplemented by letters dated May 3, 2007 and June 21, 2007, available at ADAMS Accession Nos. ML071280700 and ML071800318).

6 Official Transcript of Proceedings, Indian Point Nuclear Generating Units 2 & 3 at 3306:17-19 (Dec. 10, 2012)

(Holston) (Dec. 10, 2012 Tr.); see also Final LR- ISG-2011-03, app. A, Revised GALL Report AMP XI.M41 at A-1 (Mar. 2011) (Final LR-ISG-2011-03) (NRC000162). Some buried pipes may be located below building floor slabs. Dec. 10, 2012 Tr. at 3307:22-23 (Azevedo).

7 Dec. 10, Tr. at 3306:19-22 (Holston); see also Final LR-ISG-2011-03, App. A at A-1 (NRC000162).

8 Indian Point Energy Center License Renewal Application, app. B. at B-27 (Apr. 2007) (ENT00015B)

(LRA). As discussed in Section IV.C, infra, the BPTIP has substantially evolved since 2007 as a result of industry and plant-specific operating experience and related Staff requests for additional information (RAIs).

9 Dec. 10, 2012 Tr. at 3320:9-18, 3349:4-25, 3350:8-17 (Cox) (explaining why NUREG-1801 AMP XI.M34 was premised on opportunistic inspections and why Entergys BPTIP was a new program when the LRA was submitted in April 2007).

visual) inspection before the PEO, and one focused inspection during the first ten years of the PEO (assuming opportunistic inspections did not occur during those periods).10

6. On August 1, 2007, the NRC published a Federal Register notice of acceptance for docketing and opportunity for hearing.11 The notice explicitly clarified that proposed contentions shall be limited to matters within the scope of [license renewal].12 The notice stated that any person whose interest would be affected by the proceeding and who wished to participate as a party in the proceeding must file a petition for leave to intervene within sixty days of the notice (i.e., October 1, 2007).13 Subsequently, on October 1, 2007, the Commission extended the period for filing requests for hearing until November 30, 2007.14

7. On November 30, 2007, New York filed a petition to intervene, proposing various contentions, including NYS-5.15 As proffered in November 2007, NYS-5 alleged that Entergys AMP (i.e., BPTIP) fails to comply with 10 C.F.R. §§ 54.21(a) and 54.29 because:

(1) it does not provide for adequate inspection of all systems, structures, and components [(SSCs)] that may contain or convey water, radioactively-contaminated water, and/or other fluids; (2) there is no adequate leak prevention program designed to replace such [SSCs]

before leaks occur; and (3) there is no adequate monitoring to determine if and when leakage from these [SSCs] occurs. These [SSCs] include underground pipes, tanks, and transfer canals.16 10 LRA, app. B at B-27 (ENT00015B).

11 Entergy Nuclear Operations, Inc., Indian Point Nuclear Generating Unit Nos. 2 and 3; Notice of Acceptance for Docketing of the Application and Notice of Opportunity for Hearing Regarding Renewal of Facility Operating License Nos. DPR-26 and DPR-64 for an Additional 20-Year Period, 72 Fed. Reg. 42,134 (Aug. 1, 2007).

12 Id. at 42,135.

13 Id. at 42,134.

14 Entergy Nuclear Operations, Inc., Indian Point Nuclear Generating Unit Nos. 2 and 3; Notice of Opportunity for Hearing Regarding Renewal of Facility Operating License Nos. DPR-26 and DPR-64 for an Additional 20-Year Period: Extension of Time for Filing of Requests for Hearing or Petitions for Leave To Intervene in the License Renewal Proceeding, 72 Fed. Reg. 55,834 (Oct. 1, 2007).

15 See New York State Notice of Intention to Participate and Petition to Intervene (Nov. 30, 2007), available at ADAMS Accession No. ML073400187.

16 Id. at 80.

NYS-5 also stated that the contention applies to IP1 [i.e., IPEC, Unit 1] to the extent that Unit 2 and Unit 3 use Unit 1s buried [SSCs] that may contain or convey water, radioactively-contaminated water, and/or other fluids.17 The proposed contention was supported by the Declaration of Rudolf H. Hausler, New Yorks former consultant.

8. Entergy opposed the admission of NYS-5 on the grounds that it raised issues outside the scope of the proceeding, was not adequately supported, and failed to establish a genuine dispute on a material issue of law or fact.18 Entergy asserted that its BPTIP was consistent with the recommendations in the GALL Report, Rev. 1 and provided for adequate inspections and an adequate leak prevention program.19 In addition, Entergy cited a decision in the Pilgrim license renewal proceeding to support its position that monitoring for leakage from buried pipes and systems that does not result in a loss of intended function is outside of the scope of license renewal.20 Citing Pilgrim, Entergy also asserted that New Yorks concerns regarding leakage monitoring are covered by ongoing 10 C.F.R. Part 50 monitoring programs not within the scope of license renewal proceedings.21 Entergy further claimed that New York had not demonstrated how the examples of radiological releases at other plants cited in its contention pertain to IPEC in-scope buried systems, or explained why Entergys proposed AMP for IPEC was inadequate.22 17 Id. at 80-81.

18 Answer of Entergy Nuclear Operations, Inc. Opposing New York State Notice of Intention to Participate and Petition to Intervene at 49 (Jan. 22, 2008), available at ADAMS Accession No. ML080300149.

19 Id. at 51.

20 Id. at 49 (citing Entergy Nuclear Generation Co. and Entergy Nuclear Operations, Inc. (Pilgrim Nuclear Power Station), Licensing Board Order (Order Denying Pilgrim Watchs Motion for Reconsideration) (Jan. 11, 2008) (unpublished)).

21 Id. at 50.

22 Id. at 51.

9. The NRC Staff also opposed the admission of NYS-5, arguing that the contention raised current plant operation issues not within the scope of the proceeding, and failed to raise a genuine dispute by not alleging any specific deficiency in Entergys AMP.23 The Staff further asserted that monitoring of buried pipes and tanks as suggested by New York is a current operating issue which is addressed in the current licensing basis (CLB) and may not be challenged in license renewal proceedings.24 The Staff, like Entergy, also stated that New York had not demonstrated how the cited examples of radiological releases at other facilities relate to the adequacy of Entergys proposed license renewal BPTIP.25 Finally, the Staff disagreed with New Yorks assertion that the IPEC LRA does not discuss preventive measures.26

10. New York filed its reply on February 22, 2008, principally asserting that the Pilgrim Board order cited in Entergys and the Staffs Answers was not on point, because proposed contention NYS-5 focuses on preventing contamination from leaks that may occur during the renewal term, while the Pilgrim contention focused on ongoing monitoring of existing leaks.27 New York also argued that none of the other IPEC AMPs cited by Entergy and the NRC Staff, including the Water Chemistry Control-Primary and Secondary Program, addressed the inadequacies that New Yorks expert, Dr. Hausler, raised relative to Entergys BPTIP.28 23 NRC Staffs Response to Petitions for Leave to Intervene Filed by (1) Connecticut Attorney General Richard Blumenthal, (2) Connecticut Residents Opposed to Relicensing of Indian Point, and Nancy Burton, (3) Hudson River Sloop Clearwater, Inc., (4) The State of New York, (5) Riverkeeper, Inc., (6) The Town of Cortlandt, and (7) Westchester County at 35-36 (Jan. 22, 2008), available at ADAMS Accession No. ML080230543.

24 Id. at 35.

25 Id. at 37.

26 Id. at 38.

27 New York State Reply in Support of Petition to Intervene at 36 (Feb. 22, 2008), available at ADAMS Accession No. ML080600444.

28 See id. at 38-39.

11. On July 31, 2008, the Board admitted NYS-5 to the extent that it pertains to the adequacy of Entergys AMP for buried pipes, tanks, and transfer canals that contain radioactive fluid [and] which meet 10 C.F.R. § 54.4(a) criteria.29 According to the Board, [t]he questions to be addressed at hearing include, inter alia, whether, and to what extent, inspections of buried SSCs containing radioactive fluids, a leak prevention program, and monitoring to detect future excursions, are needed as part of Entergys AMP for these components.30 The Board stated:

[D]iscussion of proposed inspection and monitoring details will come before this Board only as they are needed to demonstrate that the Applicants AMP does or does not achieve the desired goal of providing assurance that the intended function of relevant SSCs discussed herein will be maintained for the license renewal period, and specifically, to detect, prevent, or mitigate the effects of future inadvertent radiological releases as they might affect the safety function of the buried SSCs and potentially impact public health.31 The Board also found that there is a material dispute as to the existence and adequacy of the AMP for IP1-buried SSCs that may be used by IP2 and IP3 during the PEO.32

12. The Board notes that the foregoing limitation on the scope of the admitted contention is fully consistent with the Commissions ruling in the Pilgrim license renewal proceeding on a similar contention. In CLI-10-14, the Commission affirmed the Pilgrim Boards dismissal of a buried piping contention after an evidentiary hearing and, in doing so, made clear that maintaining safety functions are the focus of the license renewal safety review under Part 29 See Indian Point, LBP-08-13, 68 NRC at 81. 10 C.F.R. § 54.4(a)(1)-(3) outline the three general categories of SSCs that fall within the scope of license renewal based on their intended safety functions.

30 Indian Point, LBP-08-13, 68 NRC at 81 (emphasis added).

31 Id. (emphasis added).

32 Id. at 82.

54not the adequacy of ongoing NRC regulatory actions to address potential radiological leakage incidents.33 B. Subsequent Revisions to the BPTIP and the NRC Staffs Safety Evaluation

13. As noted above, at the time Entergy submitted its LRA in April 2007, the BPTIP described in LRA Section B.1.6 specified one focused (direct visual) inspection before the PEO, and one focused inspection during the first ten years of the PEO (assuming opportunistic inspections did not occur during those periods).34

14. In July 2009, as a result of then-recent industry and IPEC operating experience, industry and Entergy fleet initiatives, and NRC Staff license renewal RAIs, Entergy revised the BPTIP to significantly increase the number of inspections of in-scope IPEC buried piping that it would conduct before and during the PEO.35 Entergy also revised Commitment No. 3 (i.e., its commitment to implement the BPTIP as described in LRA Section B.1.6) to include a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion.36

15. The NRC Staff issued additional RAIs in February and June 2011. By letters dated March 28, July 14, and July 27, 2011, Entergy supplemented the LRA to include revisions 33 Entergy Nuclear Generation Co. and Entergy Nuclear Operations, Inc. (Pilgrim Nuclear Power Station), CLI-10-14, 71 NRC 449, 461 (2010) (stating that NRC measures to improve the ability [of licensees] to timely detect and correct inadvertent leaks to assure compliance with public dose limits is an ongoing operational issue involving existing facilities regardless of whether those facilities are seeking or will seek license renewal).

34 Testimony of Entergy Witnesses Alan Cox, Ted Ivy, Nelson Azevedo, Robert Lee, Stephen Biagiotti, and Jon Cavallo Concerning Contention NYS-5 (Buried Piping and Tanks) at 53 (A75) (Dec. 6, 2012) (Entergy Testimony) (ENTR30373); see also LRA, App. B at B-27 (ENT00015B).

35 Entergy Testimony at 53 (A75) (ENTR30373).

36 See NL-09-106, Letter from F. Dacimo, Site Vice President, Entergy to NRC Document Control Desk, Attach.

2 at 2 (July 27, 2009) (NL-09-106) (NYS000203).

to the BPTIP.37 Entergy revised LRA Sections A.2.1.5 and A.3.1.5 (the Updated Final Safety Analysis Report (UFSAR) Supplements for IP2 and IP3) to reflect the increased number and frequency of piping inspections as well as additional soil testing. Specifically, Entergy committed to perform twenty (20) direct visual inspections of IP2 buried piping during the ten-year period prior to the PEO and fourteen (14) direct visual inspections during each 10-year period of the PEO.38 With respect to IP3, Entergy committed to performing fourteen (14) direct visual inspections of buried piping during the ten-year period prior to the PEO and sixteen (16) direct visual inspections during each ten-year period of the PEO.39 For both units, Entergy has committed to test the soil at a minimum of two locations near in-scope piping to determine representative soil conditions for each system.40 If test results indicate that the soil is corrosive, then Entergy has committed to increase the number of piping inspections to twenty (20) for IP2 and twenty-two (22) for IP3 during each ten-year period of the PEO.41 At the Staffs request, Entergy also explained that the planned inspections of in-scope buried piping that is not cathodically protected are sufficient to reasonably assure that the piping will continue to perform its intended function during the PEO.42

16. As documented in its SER and SER Supplement 1, issued in November 2009 and August 2011, respectively, the NRC Staff performed a detailed review of Entergys original and 37 Entergy Testimony at 53 (A75) (ENTR30373) (citing NL-11-074, Letter from F. Dacimo, Vice President, Entergy, to NRC Document Control Desk, Response to Request for Additional Information (RAI) Aging Management Programs, Attach. 1 at 3-4 (July 14, 2011) (NYS000152); NL-11-090, Letter from F. Dacimo, Vice President, IPEC, to NRC Document Control Desk, Clarification for Request for Additional Information (RAI) Aging Management Programs, Attach. 1 at 2-3 (July 27, 2011) (NL-11-090) (NYS000153)).

38 NL-11-090, Attach. 1 at 2 (NYS000153).

39 Id.

40 Id. at 2-3.

41 Id.

42 NL-11-032, Letter from F. Dacimo, Vice President, Entergy, to NRC Document Control Desk, Attach. 1 at 6 (Mar. 28, 2011) (NL-11-032) (NYS000151).

revised BPTIP.43 SER Supplement 1 documents the Staffs review of supplemental information provided by Entergy subsequent to the issuance of the SER, principally information provided in response to Staff RAIs. As documented in SER Supplement 1, the Staff found that the BPTIP is consistent with Section XI.M34 of NUREG-1801, Rev. 1, in addition to current industry operating experience and NRC recommendations.44 The Staff, therefore, concluded that there is reasonable assurance that IPEC buried piping within the scope of license renewal will continue to meet its design function without cathodic protection45 because: (1) recent inspections have generally found the pipings coating to be in acceptable condition, (2) soil resistivity measurements have shown the soil to be non-aggressive, (3) risk ranking of inspection locations is being used to identify those areas most susceptible to corrosion, (4) further soil samples will be obtained with the number of inspections being increased if the soil is corrosive, and (5) an adequate number of inspections have been conducted to date and are planned.46 Based on its findings, the Staff concluded that Entergy had demonstrated that it will adequately manage the pertinent aging effects on in-scope buried piping so that the systems intended function(s) will be maintained consistent with the CLB during extended operations, as required by 10 C.F.R.

§ 54.21(a)(3).47 43 SER at 3-13 to 3-18 (NYS00326B); SER Supp. 1 at 3-1 to 3-5 (NYS000160).

44 SER Supp. 1 at 3-5 (NYS000160); see also NRC Staffs Testimony of Kimberly J. Green and William C.

Holston Concerning Contention NYS-5 (Buried Pipes and Tanks) at 20-21 (A16) (Dec. 7, 2012)

(NRCR20016) (NRC Staff Testimony).

45 Cathodic protection is a technique used to reduce the corrosion of a metal surface by making that surface the cathode of an electrochemical cell. Cathodic protection is discussed further in Sections IV.B and IV.H of this decision.

46 SER Supp. 1 at 3-3 (NYS000160). Notably, with regard to these specific aspects of the Staffs safety review (coating condition, soil corrosivity, etc.), New Yorks witness, Dr. Duquette, stated: I think the staff has reasonably covered most of what we should be concerned about in this particular process. Dec. 10, 2012 Tr.

at 3478:13-15 (Duquette).

47 SER Supp. 1 at 3-4 (NYS000160).

17. New York did not file any new or amended contentions related to buried piping in response to Entergys revisions to the BPTIP and the UFSAR Supplement or the Staffs SER and supplement thereto.

C. New Yorks December 2011 Pre-filed Direct Testimony and the Parties January 2012 Joint Stipulation

18. On December 16, 2011, New York filed its initial position statement, the pre-filed testimony of Dr. David J. Duquette, and numerous exhibits related to NYS-5, including a report prepared by Dr. Duquette.48 New York and Dr. Duquette claimed, in principal part, that: (1)

Entergys BPTIP lacks sufficient detail; (2) Entergy relies on ambiguous and insufficient commitments; (3) Entergy has not provided sufficient details concerning planned inspections, acceptance criteria, and corrective actions; (4) Entergy does not know the current state or condition of IPEC buried piping; (5) Entergys data show that IPEC soils are mildly to moderately corrosive and objectively warrant cathodic protection; (6) Entergy has not committed to any corrosion mitigation measures (e.g., re-activating inoperative cathodic protection systems or installing new cathodic protection systems); (7) Nuclear Energy Institute (NEI) and Electric Power Research Institute (EPRI) guidance documents recommend that cathodic protection be installed for critical piping systems; and (8) Entergy should follow the recommendations contained in NACE SP0169-2007, Standard Practice - Control of External Corrosion on Underground or Submerged Metallic Piping Systems (NACE SP0169-2007)

(ENT000388).49 48 See State of New Yorks Initial Statement Regarding the Adequacy of Entergys Aging Management Program for Buried Pipes and Tanks (Contention NYS-5) (Dec. 16, 2011) (New York Position Statement)

(NYS000163); Pre-filed Written Testimony of Dr. David J. Duquette, Ph.D Regarding Contention NYS-5 (Dec. 16, 2011) (New York Direct Testimony) (NYS000164); Report of David J. Duquette, Ph.D in Support of Contention NYS-5 (Dec. 16, 2011) (Duquette Report) (NYS000165).

49 See generally New York Position Statement (NYS000163); New York Direct Testimony (NYS000164);

Duquette Report (NYS000165).

19. After reviewing New Yorks testimony and other submissions, the parties engaged in consultations regarding the scope of NYS-5 as pursued by New York at hearing.

Those consultations culminated in the filing of a Joint Stipulation by New York, Entergy, and the NRC Staff on January 23, 2012.50 The Joint Stipulation states that New Yorks previously-expressed concerns regarding (1) internal corrosion of buried pipes and tanks and (2) the spent fuel pool transfer canals are no longer at issue in this contention.51 Thus, in its current form, NYS-5 focuses on the management of potential aging effects caused by external corrosion of buried piping that is within the scope of license renewal and contains or may contain radioactive fluids.52 D. NRC Staffs and Entergys March 2012 Pre-filed Testimony

20. On March 30, 2012, Entergy filed its statement of position, pre-filed written testimony, and supporting exhibits.53 In its position statement, Entergy asserted that the BPTIP provides reasonable assurance that IPEC buried piping will adequately perform its intended function of maintaining plant pressure boundaries during the PEO.54 It further contended that the BPTIP readily meetsand exceedsDr. Duquettes recommendations for an adequate AMP because it: (1) adopts all applicable NEI and EPRI recommendations; (2) is consistent with 50 State of New York, Entergy Nuclear Operations, Inc., and NRC Staff Joint Stipulation (Jan. 23, 2012),

available at ADAMS Accession No. ML12023A110.

51 Id. at 1-2. As stated in the Joint Stipulation, aging management of spent fuel pool transfer canals is within the scope of the Structures Monitoring Program (LRA Section B.1.36) and not the Buried Piping and Tanks Inspection Program (LRA Section B.1.6).

52 See New York Direct Testimony at 7:12-15 (NYS000164) (stating that my report focuses on a discussion of external corrosion of pipes, specifically those in contact with soils: the factors that affect external corrosion, and the steps that may be taken to mitigate external corrosion of underground pipe).

53 Entergys Statement of Position Regarding Contention NYS-5 (Buried Piping and Tanks) (Mar. 30, 2012)

(Entergy Position Statement) (ENT000372); Testimony of Entergy Witnesses Alan Cox, Ted Ivy, Nelson Azevedo, Robert Lee, Stephen Biagiotti, and Jon Cavallo Concerning Contention NYS-5 (Buried Piping and Tanks) (Mar. 30, 2012) (ENT000373).

54 Entergy Position Statement at 2-3 (ENT000372).

NUREG-1801, Rev. 1,Section XI.M34 and meets the intent of NUREG-1801, Rev. 2,Section XI.M41;55 (3) identifies appropriate acceptance criteria for buried pipe inspections; and (4) provides for appropriate corrective actions when the acceptance criteria are not met.56 Entergy further asserted that Dr. Duquettes other criticisms of the BPTIP, including his claims related to program enforceability, cathodic protection, and soil corrosivity, lack a reliable technical and factual foundation.57 Entergy thus contended that New York had not met its evidentiary burden, and that NYS-5 should be dismissed for lack of merit.58

21. On March 29, 2012, the NRC Staff filed its statement of position, pre-filed written testimony, and supporting exhibits.59 In its statement of position, the NRC Staff stated that based on its review of Entergys BPTIP, and its assessment of Dr. Duquettes and New Yorks views concerning NYS-5, the Staff concluded that Entergy has demonstrated that the effects of aging on buried piping and tanks will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the PEO, as required by 10 C.F.R. § 54.21(a)(3).60 Further, the Staff concluded that the proposed UFSAR Supplement for the BPTIP adequately describes the program, as required by 10 C.F.R. § 54.21(d).61 The Staff emphasized that its conclusions regarding the adequacy of Entergys BPTIP reflect a thorough evaluation of Entergys LRA and related submittals, as presented in the SER and SER Supplement 1, as well 55 Id. at 4 (citing NUREG-1801, Rev. 2, Generic Aging Lessons Learned (GALL) Report (Dec. 2010) (NUREG-1801, Rev. 2 or GALL Report, Rev. 2) (NYS00147A-D)).

56 Id.

57 Id. at 19.

58 Id. at 40-42.

59 NRC Staffs Statement of Position on Contention NYS-5 (Buried Pipes and Tanks) (Aug. 23, 2012) (NRC Staff Position Statement) (NRCR00015); NRC Staff Testimony (NRCR20016); supporting exhibits at NRC000017 through NRC000029.

60 NRC Staff Position Statement at 66 (NRCR00015).

61 Id.

as careful consideration of the challenges presented by New York and Dr. Duquette.62 Accordingly, the Staff contended that NYS-5 should be resolved in favor of Entergy.63 E. New Yorks June 2012 Pre-filed Rebuttal Testimony

22. On June 29, 2012, New York filed its revised statement of position, written rebuttal testimony by Dr. Duquette, and several new exhibits referenced therein.64 In its revised position statement, New York argued that Entergy has not complied with NUREG-1801, Rev. 2, and that the NRC Staff should require Entergy to comply with that guidance because it reflects current operating experience and engineering practice.65 New York also claimed that Entergy should commit to follow the National Association for Corrosion Engineers (NACE) guidelines.66 Finally, New York asserted that all Entergy commitments or statements related to buried piping that the Board relies upon in making its relicensing decision should be enforceable license conditions.67 F. Other Prehearing Procedural Matters

1. Revisions to the Parties Evidentiary Filings

23. All three parties submitted revised versions of their pre-filed written testimony at various points prior to the December 2012 evidentiary hearing. On May 9, 2012, Entergy filed its first revision (and a revised position statement) principally to correct administrative errors related to the inadvertent exclusion of the IP2 circulating water piping and IP1 river water piping 62 Id. at 65-66.

63 Id. at 66.

64 State of New Yorks Revised Statement of Position Regarding the Adequacy of Entergys Aging Management Program for Buried Pipes and Tanks (Contention NYS-5) (June 29, 2012) (New York Revised Position Statement) (NYS000398); Pre-filed Written Rebuttal Testimony of Dr. David J. Duquette Regarding Contention NYS-5 (June 29, 2012) (NYS000399) (New York Rebuttal Testimony).

65 New York Revised Position Statement at 2.

66 Id. at 6.

67 Id. at 14.

system from background discussion identifying buried piping segments in the scope of Entergys BPTIP.68 Entergy also submitted several related exhibits and an updated witness resume.69

24. On August 23, 2012, the NRC Staff submitted a revised version of its pre-filed testimony reflecting the issuance of the Final LR-ISG-2011-03 (NRC000162), which revised the draft version of that document (NRC000019) discussed in the Staffs original testimony and position statement.70 The Staff also revised its position statement and updated its exhibits.71

25. On October 5, 2012, New York filed a revised version of its pre-filed rebuttal testimony (NYSR20399).72 New York deleted certain statements that Entergy had identified potential subjects of a motion in limine and that New York agreed to remove during the parties consultations.73

26. On October 9, 2012, Entergy submitted the second revised version of its testimony (ENTR20373), in which it corrected Figure 2 testimony to include the IP2 and IP3 68 See Entergys Statement of Position Regarding Contention NYS-5 (Buried Piping and Tanks) (May 9, 2012)

(ENTR00372); Testimony of Applicant Witnesses Alan Cox, Ted Ivy, Nelson Azevedo, Robert Lee, Stephen Biagiotti, and Jon Cavallo Concerning Contention NYS-5 (Buried Piping and Tanks) (May 9, 2012)

(ENTR00373).

69 See Unit 2 LRA Circulating Water Diagram (Submitted May 9, 2012) (ENT000402); Excerpt from NL 079, Letter from F. Dacimo, Site Vice President, Entergy, to NRC Document Control Desk, Reply to Request for Additional Information Regarding Offsite Power, Refueling Cavity, and Unit 2 Auxiliary Feedwater Pump Room Fire Event (June 12, 2009) (May 9, 2012) (NL-09-079) (ENT000403); River Water System Unit 1 Diagram (Jan. 2012) (May 9, 2012) (ENTR00422); Curriculum Vitae of Jon R. Cavallo (Revised May 9, 2012)

(ENTR00377).

70 See Letter from Sherwin E. Turk, Counsel for NRC Staff, to Administrative Judges (Aug. 29, 2012), available at ADAMS Accession No. ML12242A664; NRC Staff Testimony (NRCR20016).

71 See NRC Staff Position Statement (NRCR00015); Final LR-ISG-2011-03 (NRC000162); Interim Staff Guidance on Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 AMP XI.M41, Buried Piping and Underground Tanks, 77 Fed. Reg. 46,127 (Aug. 2, 2012) (NRC000163).

72 See Letter from Janice A. Dean, State of New York Office of the Attorney General, to Administrative Judges (Oct. 5, 2012), available at ADAMS Accession No. ML12279A260; Pre-Filed Written Rebuttal Testimony of Dr. David J. Duquette Regarding Contention NYS-5 (Oct. 5, 2012) (New York Rebuttal Testimony)

(NYSR20399).

73 See Letter from Janice A. Dean, State of New York Office of the Attorney General, to Administrative Judges (Oct. 5, 2012), available at ADAMS Accession No. ML12279A260.

floor drains, which previously had been identified as within the scope of the BPTIP but inadvertently excluded from the Figure 2.74

27. On December 6, 2012, Entergy submitted the final version of its NYS-5 testimony (ENTR30373), in which it revised the testimony to reflect the recent inclusion of approximately 270 feet of underground piping from the IP3 service water, IP3 city water, and IP2/IP3 fuel oil systems within the scope of the BPTIP.75 Entergys revised testimony explained the reason for this modification76 and referenced three new supporting exhibits.77 Additionally, Entergy submitted updated versions of four previously-admitted exhibits representing company and industry documents.78 Entergy updated its testimony to reference Final LR-ISG-2011-03 (NRC000162), and submitted a revised version of its position statement (ENTR20372) that contained conforming changes.79 74 See Testimony of Applicant Witnesses Alan Cox, Ted Ivy, Nelson Azevedo, Robert Lee, Stephen Biagiotti, and Jon Cavallo Concerning Contention NYS-5 (Buried Piping and Tanks) (Oct. 9, 2012) (ENTR20373).

75 See Entergy Testimony (ENTR30373).

76 As discussed further below, the addition of this in-scope piping (which previously was treated as accessible or non-restricted piping subject to aging management review (AMR) under another AMP) is based on clarifications of Entergys understanding of the NRCs interpretation of restricted access as used in NUREG-1801, Rev. 2 and Final LR-ISG-2011-03.

77 See Summary of Telephone Conference Call Held on October 11, 2012 Between the U.S. Nuclear Regulatory Commission and Entergy Nuclear Operations, Inc., Concerning the Indian Point Nuclear Generating Unit Nos.

2 and 3, License Renewal Application (Oct. 31, 2012) (ENT000595); NL-12-149, Letter from F. Dacimo, Entergy, to NRC Document Control Desk, Clarification of Underground Piping Information Provided in Letter NL-11-032 Regarding the License Renewal Application Indian Point Nuclear Generating Unit Nos. 2 & 3 (Oct. 18, 2012) (NL-12-149) (ENT000596); NL-12-174, Letter from F. Dacimo, Vice President, IPEC, to NRC Document Control Desk, Additional Clarification of Underground Piping Information Provided in Letter NL-12-149 Regarding the License Renewal Application Indian Point Nuclear Generating Unit Nos. 2 & 3 (Nov. 29, 2012) (NL-12-174) (ENT000597).

78 See Entergy Program Section No. CEP-UPT-0100, Rev. 1, Underground Piping and Tanks Inspection and Monitoring (Nov. 30, 2012) (CEP-UPT-0100, Rev. 1) (ENT000598); Entergy Engineering Procedure EN-DC-343, Rev. 6, Underground Piping and Tanks Inspection and Monitoring Program (Nov. 30, 2012) (EN-DC-343, Rev. 6) (ENT000599); Entergy Engineering Standard EN-EP-S-002-MULTI, Rev. 1, Underground Piping and Tanks General Visual Inspection (Nov. 30, 2012) (EN-EP-S-002-MULTI, Rev. 1) (ENT000600);

NEI 09-14, Rev. 2, Guideline for the Management of Underground Piping and Tank Integrity (Nov. 2012)

(NEI 09-14, Rev. 2) (ENT000601).

79 See Entergys Statement of Position Regarding Contention NYS-5 (Buried Piping and Tanks) (Dec. 7, 2012)

(ENTR20372).

28. Finally, on December 7, 2012, the NRC Staff submitted the revised versions of its NYS-5 testimony and position statement specifically to address the additional in-scope underground piping at IPEC.80

29. For purposes of this decision and its citations to the record, the Board hereinafter refers to the final versions of the parties position statements and testimony, as identified above.

2. NRC Staff Motion in Limine to Exclude New York Rebuttal Exhibits

30. On July 30, 2012, the NRC Staff filed a motion in limine seeking to strike three exhibits included with New Yorks June 29, 2012 rebuttal evidentiary filings: NYS000400, NYS000401, and NYS000402.81 The Staff argued that the cited exhibits were unrelated to the IPEC LRA, lacked sponsoring witnesses, and exceeded the proper scope of rebuttal evidence.82

31. The Board denied the NRC Staffs motion (among other in limine motions filed by the parties) in a bench ruling issued on October 15, 2012, the first day of evidentiary hearings, opting to receive the contested exhibits into evidence and to accord them their due weight.83

3. New Yorks August 2012 Motion for Cross-Examination

32. On August 8, 2012, New York filed a motion with respect to its seven Track 1 contentions,84 seeking to invoke its purported statutorily-granted cross-examination rights under 80 See NRC Staff Testimony (NRCR20016); NRC Staffs Statement of Position on Contention NYS-5 (Buried Pipes and Tanks) (Aug. 23, 2012) (NRCR20015).

81 See NRC Staffs Motion in Limine to Exclude Certain Rebuttal Exhibits Filed by the State of New York Concerning Contention NYS-5 (Buried Piping and Tanks) (July 30, 2012) (NRC Staff July 30, 2012 Motion in Limine), available at ADAMS Accession No. ML12212A349; Official Transcript of Proceedings, Entergy Nuclear Vermont Yankee (July 23, 2008) (NYS000400); Excerpt from Appendix B to the License Renewal Application for Grand Gulf Nuclear Station (NYS000401); Declaration of Janice A. Dean (June 28, 2012)

(NYS000402) (attesting to the authenticity of the Ex. NYS000400 and NYS000401).

82 Exhibit NYS000400 included remarks of a legal nature made by an administrative judge in the Vermont Yankee license renewal proceeding. Exhibit NYS000401 related to the use of cathodic protection at another Entergy plant (Grand Gulf). Exhibit NYS000402 is a declaration by New York counsel attesting to the authenticity of the prior two exhibits. See NRC Staff July 30, 2012 Motion in Limine at 5-7. Entergy supported the Staffs motion. See id. at 9.

83 Official Transcript of Proceedings, Indian Point Nuclear Generating Units 2 & 3 at 1265-66 (Oct. 15, 2012)

(Oct. 15, 2012 Tr.).

Section 274(l) of the Atomic Energy Act (AEA), 42 U.S.C. § 2021(l).85 Specifically, New York claimed that as the host state to IPEC, Section 274(l) confers upon it expansive cross-examination rights that take precedence over the restrictive cross-examination rights allowed pursuant to 10 C.F.R. §§ 2.315(c) and 2.1204(b)(3).86 It argued that the 2004 modifications to the NRCs Administrative Procedure Act-compliant regulations, which it contended generally restrict the use of cross-examination by most parties, do not purport to address the rights preserved to the States in [Section 2021(l)].87 Thus, New York asserted, 10 C.F.R. §§ 2.135(c) and 2.1204(b)(3) do not apply to it as a host state and do not restrict its right to interrogate witnesses.88 Both Entergy and the NRC Staff opposed the motion as lacking a legal basis,89 arguing that New York mischaracterized as an absolute right what is actually a reasonable opportunity to cross-examine witnesses.90 84 Track 1 contentions consist of Riverkeeper TC-2 (Flow-Accelerated Corrosion), NYS-12C (SAMA Analysis -

Decontamination Costs), NYS-16B (SAMA Analysis - Population Estimate), NYS-17B (Land Values), NYS-37 (Energy Alternatives), Clearwater EC-3A (Environmental Justice), NYS-5 (Buried Piping), NYS-6/7 (Non-EQ Cables), and NYS-8 (Transformers). Prior to the October 2012 hearings, the parties settled another Track 1 contention, Riverkeeper EC-3/Clearwater EC-1 (Spent Fuel Pool Leaks to Groundwater). The Board approved that settlement agreement on October 17, 2012. Licensing Board Consent Order (Approving Settlement of Consolidated Contention Riverkeeper EC-3 and Clearwater EC-1) (Oct. 17, 2012) (unpublished).

85 State of New York Motion to Implement Statutorily-Granted Cross-Examination Rights Under Atomic Energy Act § 274(l) at 1 (Aug. 8, 2012), available at ADAMS Accession No. ML12221A483.

86 Id. at 14-15, 19.

87 Id. at 14.

88 Id. at 15.

89 Entergys Answer Opposing New York States Motion to Cross-Examine (Aug. 20, 2012) (Entergy Answer Opposing New York Motion), available at ADAMS Accession No. ML12233A371; NRC Staffs Answer to State of New Yorks Motion to Implement Statutorily-Granted Cross-Examination Rights under Atomic Entergy Act § 274(l) (Aug. 20, 2012) (Staff Answer Opposing New York Motion), available at ADAMS Accession No. ML12233A742.

90 Entergy Answer Opposing New York Motion at 3-4, Staff Answer Opposing New York Motion at 9-10.

33. On August 29, 2012, in accordance with 10 C.F.R. § 2.1207(a)(3) and the Boards Scheduling Order, Entergy (and the other parties) submitted in camera proposed questions for the Board to consider asking to the other parties witnesses on Contention NYS-5.91

34. In an Order issued on September 21, 2012, the Board granted, in part, New Yorks August 8, 2012 motion for cross-examination of witnesses during the evidentiary hearings.92 The Board found that New Yorks opportunity to cross-examine witnesses is bound by the same 10 C.F.R. Part 2 regulations that govern all parties to this proceeding.93 As a result, the Board found it unnecessary to address whether and if so to what extent, in some theoretical sense, the right to cross-examination granted to host states by the AEA may be different from those provided to parties under 10 C.F.R. Part 2.94 Citing 10 C.F.R. § 2.1204(b)(1), the Board noted that in any oral hearing held under Subpart L, a party may file a motion (accompanied by a cross-examination plan) seeking cross-examination by the parties on particular admitted contentions or issues.95 Pursuant to 10 C.F.R. § 2.1204(b)(3), the presiding officer may allow cross-examination by the parties only if the presiding officer determines that cross-examination by the parties is necessary to ensure the development of an adequate record for decision.96

35. The Board concluded that New York had complied with 10 C.F.R. § 2.1204(b) by filing the motion for cross-examination and proposed examination questions before the August 91 10 C.F.R. § 2.1207(a)(3)(iii).

92 Licensing Board Order (Order Granting, in part, New Yorks Motion for Cross Examination) (Sept. 21, 2012)

(Sept. 21, 2012 Order) (unpublished); see also Licensing Board Errata (Regarding Order Granting, in part, New Yorks Motion for Cross Examination) (Sept. 25, 2012) (unpublished).

93 Sept. 21, 2012 Order at 5.

94 Id. at 5-6.

95 Id. at 6.

96 Id. (quoting 10 C.F.R. § 2.1204(b)(3)).

29, 2012, deadline for those submittals.97 Citing the voluminous and technical nature of the parties evidentiary submissions, the Board determined that granting New Yorks request for cross-examination was necessary to ensure development of an adequate record for this proceeding.98 It thus ruled that during the hearing, New York could examine witnesses following the Boards examination, as long as its questions were relevant, reasonable, and non-repetitive.99

36. On September 24, 2012, the Board discussed its Order in a pre-hearing conference call in response to questions from the NRC Staff and Entergy.100 During that conference, Chairman McDade confirmed that New York would have the opportunity to examine witnesses on areas that the Board missed in its own witness examinations.101 He also suggested that the Board might limit New Yorks questioning if it becomes repetitive102 and stated that other parties would have a reasonable opportunity to interrogate witness on discrete issues through oral motions at the hearing if they made a sufficiently compelling request and avoided repetitive questions.103

37. Subsequently, on September 28, 2012, Entergy filed an emergency petition for interlocutory review of the Boards order with the Commission.104 Entergy requested, and was 97 Id.

98 Id.

99 Id. at 6-7.

100 Official Transcript of Proceedings, Indian Point Nuclear Generating Units 1 & 2 [sic2 & 3] (Sept. 24, 2012).

101 Id. at 1238:1-6 (McDade) 102 Id.

103 Id. at 1239:21-1241:8 (McDade).

104 Entergys Emergency Petition for Interlocutory Review of Board Order Granting Cross-Examination to New York State and Request for Expedited Briefing (Sept. 28, 2012), available at ADAMS Accession No. ML12272A363.

granted, expedited briefing on its petition.105 New York opposed Entergys petition106 and the Staff supported it.107

38. On October 12, 2012, the Commission denied Entergys request for interlocutory review, noting that the Board has the responsibility in the first instance to oversee the development of an adequate case record.108 In so ruling, the Commission cited Chairman McDades assurances, made during the September 24, 2012 prehearing conference call, that the Board would prohibit open-ended, lengthy, repetitive, and immaterial cross-examination, and allow all parties a full and fair opportunity to request cross-examination.109 The Commission further stated its expectation that the Board would act on cross-examination requests fairly and evenhandedly, rigorously oversee any cross-examination it allowed, and limit the cross-examination to supplemental and genuinely material inquiries, necessary to develop an adequate and fair record.110

39. During the hearing on the first contention (Riverkeeper TC-2), the Board indicated that it would allow questioning of the witnesses by the petitioner (there, Riverkeeper, Inc. (Riverkeeper)), Entergy, and the NRC Staff.111 Entergy objected to examination of 105 Id.; Commission Order (Oct. 2, 2012) (unpublished).

106 State of New York Combined Opposition to Entergys Requests for Emergency Stay and Interlocutory Review of the Board Order Granting Limited Cross Examination (Oct. 1, 2012), available at ADAMS Accession No. ML12275A327. Entergy replied in opposition to New Yorks answer. See Entergys Reply to New York States Opposition to Entergys Emergency Petition for Interlocutory Review (Oct. 8, 2012), available at ADAMS Accession No. ML12282A002.

107 NRC Staffs Answer to Entergys Emergency Petition for Interlocutory Review, and Application for Stay, of the Boards Order of September 21, 2012 (Oct. 5, 2012), available at ADAMS Accession No. ML12279A309.

108 Entergy Nuclear Generation Co. (Indian Point Nuclear Generating Units 2 & 3) CLI-12-18, 76 NRC __ slip op. at 6 (Oct. 12, 2012).

109 Id. at 3-4.

110 Id. at 7.

111 Official Transcript of Proceedings, Indian Point Nuclear Generating Units 2 & 3 at 1797:16-24 (McDade) (Oct.

17, 2012).

witnesses by any party, and requested that the Board close the record on that contention.112 In support, Entergy: (1) noted that Riverkeeper had not made, nor been required to make, the sort of showing contemplated by the Subpart L regulations, which was a circumstance that the Commission had found troubling; (2) argued that no sufficient constraints had been placed on examination by parties; (3) noted that the procedure, rather than constituting the rare occurrence contemplated by the Commission, was apparently being undertaken as the norm for these proceedings; and (4) argued that, with two full days of Board questioning, additional questioning by the parties was not truly necessary, as mandated by the Commission.113 In the alternative, Entergy requested reciprocal treatment; i.e., that it be afforded the same direct and cross-examination rights as the other parties.114

40. The Board denied Entergys motion to preclude party examination of witnesses, stating any additional showing need not be articulated, and that the Board envisioned allowing Riverkeeper, then Entergy, and then the Staff brief opportunities to conduct limited interrogation of the witnesses.115 During hearing on the second contention (NYS-12C), Entergy reiterated its objection, which was again denied by the Board, and Entergy asked that the Board recognize Entergys standing objection on such grounds with respect to all remaining contentions.116 Upon that basis, Entergy rested upon its standing objection, and did not repeat its procedural arguments in connection with NYS-5 or subsequent contentions.

112 Id. at 1794:11-1797:15 (Fagg).

113 Id.

114 Id. at 1797:8-14 (Fagg).

115 Id. at 1797:16-1800:10 (McDade).

116 Official Transcript of Proceedings, Indian Point Nuclear Generating Units 2 & 3 at 2315-16 (Oct. 18, 2012).

G. The December 10 and 11, 2012 Evidentiary Hearing

41. On October 15, 2012, the Board commenced its evidentiary hearing and admitted into evidence the testimony and exhibits offered by the parties.117 On December 10 and 11, 2012, the Board held the evidentiary hearing on NYS-5 at the DoubleTree Hotel located in Tarrytown, New York.118

42. The Board conducted the hearing in accordance with the provisions of Subpart L to 10 C.F.R. Part 2. In accordance with its September 21, 2012 Order, and the Commissions related guidance in CLI-12-18, the Board permitted limited cross-examination and redirect examination by all parties. Thus, during the hearings, the witnesses responded principally to questions from the Board and, to a lesser extent, to questions posed by counsel.

43. Following the hearing, on January 11, 2013, Entergy and New York filed a Joint Motion for Leave to File Additional Hearing Exhibits for Admission Into Evidence, seeking the admission of several new exhibits related to NYS-5 (among other contentions).119 The Board admitted those exhibits into evidence by Order dated January 15, 2013.120

44. The parties jointly submitted proposed corrections to the hearing transcript on February 5, 2013.121 On February 28, 2013, the Board issued an Order adopting the parties proposed transcript corrections.122 117 Oct. 15, 2012 Tr. at 1268-70.

118 See Dec. 10, 2012 Tr.; Official Transcript of Proceedings, Indian Point Nuclear Generating Units 2 & 3 (Dec.

11, 2012) (Dec. 11, 2012 Tr.).

119 Entergy and the State of New York Joint Motion for Leave to file Additional Hearing Exhibits (Jan. 11, 2013),

available at ADAMS Accession No. ML13011A396.

120 Licensing Board Order (Scheduling Post-Hearing Matters and Ruling on Motions to File Additional Exhibits) at 5 (Jan. 15, 2013) (unpublished).

121 Letter from Counsel for Entergy Nuclear Operations, Inc., Counsel for Riverkeeper, Inc., Counsel for the State of New York, Counsel for the NRC Staff, and Counsel for Hudson [River] Sloop Clearwater, Inc., to Lawrence G. McDade, Chairman, Dr. Michael F. Kennedy, and Dr. Richard Wardwell, Atomic Safety and Licensing Board (Feb. 5, 2013), available at ADAMS Accession No. ML13036A437.

45. On March 22, 2013, the parties submitted proposed findings of fact and conclusions of law in the form of a proposed Initial Decision by the Board.

III. APPLICABLE LEGAL AND REGULATORY STANDARDS A. Scope of License Renewal Review Under 10 C.F.R. Part 54

46. In the context of license renewal, the Commission has specifically limited its safety review of LRAs to the matters specified in 10 C.F.R. §§ 54.21 and 54.29(a)(2), which focus on the aging management of certain SSCs.123 The Commissions license renewal regulations reflect the distinction between 10 C.F.R. Part 54 aging management issues on the one hand, and ongoing 10 C.F.R. Part 50 regulatory process (e.g., security, radiological, and emergency planning issues) on the other.124 The NRCs longstanding regulatory framework is premised upon the notion that, with the exception of aging management issues, the NRCs ongoing regulatory process is adequate to ensure that the CLB of an operating plant provides and maintains an acceptable level of safety.125

47. Consequently, the matters before the Board in this proceeding are limited to whether IP2 and IP3 can be safely operated in the PEO, that is, beyond the current expiration of the licenses in 2013 and 2015, respectively.126 Issues regarding the adequacy of the design and construction of the facility are, therefore, outside the scope of matters appropriately considered here.127 122 Licensing Board Order (Adopting Proposed Transcript Corrections and Resolving Contested Corrections)

(Feb. 28, 2013) (unpublished).

123 See Fla. Power & Light Co. (Turkey Point Nuclear Generating Plant, Units 3 & 4), CLI-01-17, 54 NRC 7, 8 (2001); Duke Energy Corp. (McGuire Nuclear Station, Units 1 & 2), CLI-02-26, 56 NRC 358, 363 (2002).

124 Turkey Point, CLI-01-17, 54 NRC at 7.

125 See Nuclear Power Plant License Renewal; Revisions, 56 Fed. Reg. 64, 943, 64,946 (Dec. 13, 1991).

126 Turkey Point, CLI-01-17, 54 NRC at 8.

127 In that regard, when the Commission issues an initial license, it makes a comprehensive determination that the design, construction, and proposed operation of the facility satisfied the Commissions requirements and

48. 10 C.F.R. § 54.4(a)(1)-(3) outline the three general categories of SSCs that fall within the scope of license renewal. From among these SSCs, license renewal applicants must identify and list, in an integrated plant assessment, those structures and components subject to an AMR. 10 C.F.R. § 54.21 provides the standards for determining which structures and components require an AMR.

49. The first category consists of all safety-related SSCs.128 These are SSCs that are relied upon to remain functional during and following design basis events to ensure the integrity of the reactor coolant pressure boundary, the capability to shut down the reactor and maintain it in a safe shutdown condition, or the capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to those referred to in 10 C.F.R. §§ 50.34(a)(1), 50.67(b)(2), or 100.11.129

50. The second category consists of all non-safety-related SSCs whose failure could prevent satisfactory accomplishment of any of the safety functions identified in 10 C.F.R.

§ 54.4(a)(1)(i)- (iii).130 For example, SSCs in this category include a non-safety-related system that fails during a postulated design basis accident earthquake and, as a result, prevents a safety-related SSC from performing its intended safety function.

51. The third category consists of all SSCs relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the NRCs regulations for fire protection (10 C.F.R. § 50.48), environmental qualification (10 C.F.R. § 50.49), pressurized thermal shock (10 C.F.R. § 50.61), anticipated transients without scram (10 C.F.R. § 50.62), and provided reasonable assurance of adequate protection to the public health and safety and common defense and security. Nuclear Power Plant License Renewal; Revisions, 56 Fed. Reg. at 64,947.

128 10 C.F.R. § 54.4(a)(1).

129 Id. § 54.21; see id. § 50.2 (defining safety-related structures, systems and components).

130 Id. § 54.4(a)(2).

station blackout (10 C.F.R. § 50.63).131 These SSCs would include, for example, main or auxiliary systems necessary to meet these regulations, as defined in a plants FSAR, and a plants fire protection systems.

52. If a structure or component performs no intended function as defined in 10 C.F.R.

§ 54.4(a)(1)-(3), then it is not subject to AMR.132 Section 54.21(a)(1)(i), in turn, further limits the structures and components subject to AMR to those structures and components that perform an intended function, as described in § 54.4(a)(1)-(3), without moving parts or without a change in configuration or properties, and that are not subject to replacement based on a qualified life or specified time period.133

53. Given the foregoing requirements, the preparation of an LRA involves a sequential, two-step process: (1) identification of the SSCs within the scope of the license renewal rule (as defined in 10 C.F.R. § 54.4) (also known as scoping) and then, among those in-scope SSCs, (2) identification of the structures and components that are subject to AMR (also known as screening). Screening is part of an applicants integrated plant assessment, as defined in 10 C.F.R. § 54.21, and is performed to determine which structures and components in the scope of license renewal require AMR. Section 54.21(a)(1)(i) lists examples of structures and components that require AMR. Piping appears on that list.134 B. Reasonable Assurance Standard

54. For safety issues, pursuant to 10 C.F.R. § 54.29(a), the NRC will issue a renewed license if it finds that actions have been identified and have been or will be taken by the 131 Id. § 54.4(a)(3).

132 Id. § 54.4(b).

133 Id. § 54.21(a)(1)(i)-(ii).

134 Id. § 54.21(a)(1)(i).

applicant, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the CLB.135

55. Longstanding Commission and judicial precedent makes clear that the reasonable assurance standard does not require an applicant to meet an absolute or beyond a reasonable doubt standard.136 Rather, the Commission evaluates an application on a case-by-case approach, applying sound technical judgment and verifying the applicants compliance with Commission regulations.137 A touchstone for determining whether the reasonable assurance standard is satisfied is compliance with Commission regulations.138 C. Demonstration of Reasonable Assurance Through Consistency with NUREG-1801 (the GALL Report)

56. The NRC Staff verifies compliance with the NRCs license renewal regulations through its comprehensive LRA review process, which includes, among other things, review of the LRA and final safety analysis report (FSAR) supplement, the issuance of RAIs, the conduct of onsite audits and inspections, and the preparation of a detailed SER.139 To determine whether an LRA complies with NRC regulations, the Staff reviews an LRA against the 135 Entergy Testimony at 22 (A38) (ENTR30373); NRC Staff Testimony at 9-13 (A8) (NRCR20016).

136 AmerGen Energy Co. LLC (Oyster Creek Generating Station), CLI-09-7, 69 NRC 235, 263-64 (2009), affd sub nom. N.J. Envtl. Fedn v. NRC, 645 F.3d 220 (3d Cir. 2011); Commonwealth Edison Co. (Zion Station, Units 1 & 2), ALAB-616, 12 NRC 419, 421 (1980); N. Anna Envtl. Coal. v. NRC, 533 F.2d 655, 667-68 (D.C.

Cir. 1976) (rejecting the argument that reasonable assurance requires proof beyond a reasonable doubt and noting that the licensing board equated reasonable assurance with a clear preponderance of the evidence);

see also Dec. 11, 2012 Tr. at 3859:14-15 (Holston) (stating that the applicable regulatory standard is reasonable assurance, not absolute uncertainty).

137 See Oyster Creek, CLI-09-7, 69 NRC at 263; Pilgrim, CLI-10-14, 71 NRC at 465-66.

138 See Me. Yankee Atomic Power Co. (Me. Yankee Atomic Power Station), ALAB-161, 6 AEC 1003, 1009 (1973).

139 Dec. 10, 2012 Tr. at 3323:9-12 (Holston) (stating that the NRC Staff confirms compliance with GALL Report program elements through AMP audits); see also id. at 3324:6-25 (describing the NRC Staffs license renewal AMP audit process); id. at 3364:18-3365-16 (Holston) (describing the NRC Staffs review of operating experience and related corrective actions as part of the AMP audit process).

requirements set forth in 10 C.F.R. Part 54, as well as Staff guidance contained in NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants.140

57. As mentioned previously, the GALL Report provides the technical basis for NUREG-1800 and identifies AMPs that the Staff has accepted as meeting the requirements of Part 54.141 For each AMP, the GALL Report describes ten program elements that the Staff evaluates: (1) Scope of the Program; (2) Preventive Actions; (3) Parameters Monitored or Specified; (4) Detection of Aging Effects; (5) Monitoring and Trending; (6) Acceptance Criteria; (7) Corrective Actions; (8) Confirmation Process; (9) Administrative Controls; and (10)

Operating Experience.142

58. As noted in the guidance, the GALL Report is treated in the same manner as an NRC-approved topical report that is generically applicable.143 Therefore, an applicant may reference the GALL Report in an LRA to demonstrate that its AMPs correspond to those that the NRC staff previously reviewed and approved in the GALL Report.144 As the Staff has indicated, adherence to GALL Report guidance thus constitutes one acceptable way to manage aging effects for license renewal.145 The Commission has confirmed this approach: [A] license 140 NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants, Rev. 1 (Sept. 2005) (NUREG-1800) (NYS000195).

141 GALL Report, Rev. 2 at 8 (NYS00147A).

142 Id. at 6.

143 Id. at 8; see also Dec. 10, 2012 Tr. at 3408:11-3409:6 (Green) (discussing the NRCs treatment of the GALL Report as a topical report).

144 GALL Report, Rev. 2 at 8 (NYS00147A).

145 Id. Although the GALL Report is a guidance document, it is entitled to special weight in an adjudicatory proceeding. NextEra Energy Seabrook, LLC (Seabrook Station, Unit 1), CLI-12-05, 75 NRC __, slip op. at 16 n.78 (Mar. 8, 2012) (quoting Private Fuel Storage, L.L.C. (Indep. Spent Fuel Storage Installation), CLI-01-22, 54 NRC 255, 264 (2001)).

renewal applicants use of an [AMP] identified in the GALL Report constitutes reasonable assurance that it will manage the targeted aging effect during the renewal period.146

59. In Oyster Creek, the Commission expressly interpreted section 54.21(c)(1) to permit a demonstration [that the aging effects will be adequately managed for the PEO] after the issuance of a renewed license.147 Similarly, the Commission has stated that a commitment to implement an AMP that the NRC finds is consistent with the GALL Report constitutes one acceptable method for compliance with 10 C.F.R. § 54.21(c)(1)(iii).148 D. Demonstration of Reasonable Assurance Through Licensee Commitments

60. The demonstration of reasonable assurance through the identification of future actions (i.e., commitments) is a bedrock principle of the license renewal process in 10 C.F.R.

Part 54.149 Licensee commitments are a well-established and essential mechanism for ensuring that licensees implement their AMPs in a timely and effective manner.150 This principle dates back to the original 1991 license renewal rule, in which the Commission specified that the license renewal process would rely on new commitments to monitor, manage, and correct age-related degradation.151 Accordingly, it is permissible for an applicant to incorporate commitments in its LRA, and for the Staff to review and rely on such commitments in making its reasonable assurance determination.152 146 See AmerGen Energy Co., LLC, (Oyster Creek Nuclear Generating Station), CLI-08-23, 68 NRC 461, 468 (emphasis added); see also Seabrook, CLI-12-05, slip op. at 18.

147 Entergy Nuclear Vermont Yankee, L.L.C. and Entergy Nuclear Operations, Inc. (Vt. Yankee Nuclear Power Station), CLI-10-17, 72 NRC 1, 36 (2010) (citing Oyster Creek, CLI-08-23, 68 NRC at 468)).

148 Id.

149 Id. at 37.

150 See id.

151 See Nuclear Power Plant License Renewal, 56 Fed. Reg. at 64,946.

152 See Vt. Yankee, CLI-10-17, 72 NRC at 37.

61. Commitments are tracked by licensees and monitored and inspected by the NRC Staff. This applies equally to commitments made during current operation under Part 50 or made for license renewal under Part 54. Once a renewed license is issued, license renewal commitments become part of the CLB, which is enforced by the NRC under its ongoing Part 50 oversight process.153 The licensing basis for a nuclear power plant during the renewal term will consist of the CLB and new commitments to address the requirements of license renewal.154

62. With respect to licensee commitments, the Commission has long declined to assume that licensees will refuse to meet their obligations, given that licensees remain subject to continuing NRC oversight, inspection, and enforcement authority throughout the operating license term.155 In that regard, the NRC Staff continuously inspects and enforces licensee commitments, including license renewal commitments, as part of its ongoing regulatory oversight process under 10 C.F.R. Part 50separate and apart from its review of an LRA.156 Further, the license renewal process is premised on the assumption that the NRC Staff will adequately perform its oversight functions.157 Accordingly, any question as to the adequacy of 153 See 10 C.F.R. §§ 54.3, 54.33.

154 Nuclear Power Plant License Renewal, 56 Fed. Reg. at 64,946.

155 See, e.g., Pac. Gas & Elec. Co. (Diablo Canyon Nuclear Power Plant, Units 1 & 2), CLI-03-2, 57 NRC 19, 29 (2003) (in denying a petition to intervene, the Commission held that the intervenor had not provided any reason (via submission of facts or expert opinion) to believe that the licensee would fail to meet its regulatory obligations).

156 Oyster Creek, CLI-09-7, 69 NRC at 284 (holding that review of the applicants compliance with a commitment to perform a finite element structural analysis of the drywell was not a precondition for granting the renewed operating license); see also id. ([R]eview and enforcement of license conditions is a normal part of the Staffs oversight function rather than an adjudicatory matter.).

157 See Turkey Point, CLI-01-17, 54 NRC at 9 (holding that just as oversight programs help assure compliance with the [CLB] during the original license term, they likewise can reasonably be expected to fulfill this function during the renewal term).

the NRC Staffs oversight and enforcement activities with respect to commitments is outside the scope of this proceeding.158 E. Burden of Proof

63. At the hearing stage, an intervenor has the initial burden of going forward; i.e.,

it must provide sufficient evidence to support the claims made in the admitted contention.159 The mere admission of the contention does not satisfy that burden.160 Moreover, an intervenor cannot meet its burden by relying on unsupported allegations and speculation.161 Rather, it must introduce sufficient evidence during the hearing phase to establish a prima facie case.162 If it does so, then the burden shifts to the applicant to provide sufficient evidence to rebut the intervenors contention.163 158 Id. at 10 (Adjudicatory hearings in individual license renewal proceedings will share the same scope of issues as our NRC staff review, for our hearing process (like our staff's review) necessarily examines only the questions our safety rules make pertinent.)

159 Oyster Creek, CLI-09-7, 69 NRC at 269 (quoting Consumers Power Co. (Midland Plant, Units 1 & 2), ALAB-123, 6 AEC 331, 345 (1973)) (The ultimate burden of proof on the question of whether the permit or license should be issued is . . . upon the applicant. But where . . . one of the other parties contends that, for a specific reason . . . the permit or license should be denied, that party has the burden of going forward with evidence to buttress that contention. Once he has introduced sufficient evidence to establish a prima facie case, the burden then shifts to the applicant who, as part of his overall burden of proof, must provide a sufficient rebuttal to satisfy the Board that it should reject the contention as a basis for denial of the permit or license.) (emphasis in original); see also Vt. Yankee Nuclear Power Corp. v. Natural Res. Def. Council, 435 U.S. 519, 554 (1978)

(upholding this threshold test for intervenor participation in licensing proceedings); Phila. Elec. Co. (Limerick Generating Station, Units 1 & 2), ALAB-262, 1 NRC 163, 191 (1975) (holding that the intervenors had the burden of introducing evidence to demonstrate that the basis for their contention was more than theoretical).

160 See Midland, ALAB-123, 6 AEC at 345.

161 See Oyster Creek, CLI-09-7, 69 NRC 268-70; see also Phila. Elec. Co. (Limerick Generating Station, Units 1

& 2), ALAB-857, 25 NRC 7, 13 (1987) (stating that an intervenor may not merely assert a need for more current information without having raised any questions concerning the accuracy of the applicants submitted facts).

162 See Oyster Creek, CLI-9-07, 69 NRC at 268-70.

163 See, e.g., 10 C.F.R. § 2.325; La. Power & Light Co. (Waterford Steam Electric Station, Unit 3), ALAB-732, 17 NRC 1076, 1093 (1983) (citing Midland, ALAB-123, 6 AEC at 345).

64. Ultimately, a preponderance of the evidence must support the applicants position.164 A preponderance of the evidence requires the trier of fact to believe that the existence of a fact is more probable than its nonexistence.165 IV. FACTUAL FINDINGS AND LEGAL CONCLUSIONS A. Witnesses and Evidence Presented

1. Entergys Expert Witnesses

65. Entergy presented written and oral testimony by a panel of six witnesses: (1) Mr.

Alan B. Cox, (2) Mr. Ted S. Ivy, (3) Mr. Nelson F. Azevedo, (4) Mr. Robert C. Lee, (5) Mr.

Stephen F. Biagiotti, Jr., and (6) Mr. Jon R. Cavallo.

a. Mr. Alan B. Cox

66. Mr. Cox is Entergys Technical Manager, License Renewal.166 Mr. Cox has more than thirty-five years of experience in the nuclear power industry, having served in various positions related to nuclear power plant engineering and operations. As Technical Manager, Mr.

Cox was directly involved in preparing the LRA and developing or reviewing AMPs for IP2 and IP3, including the BPTIP. Mr. Cox was also directly involved in developing or reviewing Entergy responses to NRC Staff RAIs concerning the LRA and revisions to the application, principally as they relate to aging management issues. In addition, Mr. Cox has been a member of the NEI License Renewal Task Force since approximately 2002 and has previously represented Entergy on the NEI License Renewal Mechanical Working Group and the NEI License Renewal Electrical Working Group. Mr. Cox also supported Entergy at the related 164 See Pac. Gas & Elec. Co. (Diablo Canyon Nuclear Power Plant, Units 1 & 2), ALAB-763, 19 NRC 571, 577 (1984).

165 Concrete Pipe & Products of Cal., Inc. v. Construction Laborers Pension Trust for Southern Cal., 508 U.S.

602, 622 (1993) (internal quotation marks and citation omitted).

166 Mr. Coxs professional qualifications are provided in his statement of qualifications (ENT000031) and summarized in his testimony. See Entergy Testimony at 1-2 (A2-4) (ENTR30373).

Advisory Committee on Reactor Safeguards Subcommittee and Full Committee meetings for the IPEC LRA held in March 2009 and September 2009, respectively. Mr. Cox holds a Bachelor of Science (B.S.) degree in Nuclear Engineering from the University of Oklahoma and a Masters of Business Administration (M.B.A.) degree from the University of Arkansas at Little Rock.

b. Mr. Ted S. Ivy

67. Mr. Ivy is Entergys Manager, License Renewal.167 Mr. Ivy has more than twenty-five years of experience in the nuclear industry and is a licensed Professional Engineer in the States of Arkansas and Louisiana. Mr. Ivy is a member of the American Society of Mechanical Engineers (ASME), NACE International (formerly NACE), and the EPRI Buried Piping Integrity Group. Additionally, he is Entergys representative on the NEI License Renewal Mechanical Working Group and served as Vice Chairman (2009-2010) and Chairman (2010) of that organization. As a member of the Entergy License Renewal Services team, Mr.

Ivy has been directly involved in seven license renewal projects, including the IPEC project. His principal responsibilities with respect to the IPEC LRA have included: (1) preparation and review of license renewal project guidelines on scoping, screening, mechanical AMRs, and time-limited aging analyses (TLAAs); (2) preparation and review of Class 1 and Non-Class 1 mechanical AMR and AMP evaluation reports; and (3) review of Class 1 and Non-Class 1 mechanical portions of the LRA and preparation of related responses to NRC Staff RAIs. These responsibilities have encompassed review of the BPTIP and revisions to that program. Mr. Ivy holds a B.S. degree in Mechanical Engineering from the University of Arkansas and an M.B.A.

from the University of Arkansas at Little Rock.

167 Mr. Ivys professional qualifications are provided in his statement of qualifications (ENT000374) and summarized in his testimony. See Entergy Testimony at 2-4 (A6-8) (ENTR30373).

c. Mr. Nelson F. Azevedo

68. Mr. Azevedo is Entergys Supervisor of Code Programs at IPEC.168 He has approximately thirty years of professional experience in the nuclear power industry. In his current position, Mr. Azevedo oversees the IPEC engineering section responsible for implementing ASME Code programs, including the buried piping, fatigue monitoring, inservice inspection, inservice testing, flow-accelerated corrosion, snubber testing, boric acid corrosion control, non-destructive examination, steam generators, alloy 600 cracking, reactor vessel embrittlement, reactor vessel internals, welding, and 10 C.F.R. Part 50, Appendix J containment leakrate programs. He also is responsible for ensuring compliance with ASME Code,Section XI requirements for repair and replacement activities at IPEC and represents IPEC before industry organizations, including the pressurized water reactor (PWR) Owners Group Management Committee. Mr. Azevedo holds a B.S. degree in Mechanical and Materials Engineering from the University of Connecticut, and Master of Science (M.S.) in Mechanical Engineering and M.B.A. degrees from the Rensselaer Polytechnic Institute (RPI) in Troy, New York.

d. Mr. Robert C. Lee

69. Mr. Lee is a former Senior Engineer in Code Programs at IPEC.169 Mr. Lee is a licensed Professional Engineer in the State of New York and has approximately thirty years of experience in the nuclear power industry. His nuclear experience principally has been in the Design/Analysis groups with Combustion Engineering, the New York Power Authority, and Entergy. As a Senior Engineer in the IPEC Code Programs group, Mr. Lee was the lead for 168 Mr. Azevedos professional qualifications are provided in his statement of qualifications (ENT000032) and summarized in his testimony. See Entergy Testimony at 4-5 (A10-12) (ENTR30373).

169 Mr. Lees professional qualifications are provided in his statement of qualifications (ENT000375) and summarized in his testimony. See Entergy Testimony at 5-6 (A14-16) (ENTR30373). Mr. Lee retired from Entergy effective March 1, 2013.

several technical programs, including the UPTIMP, Entergys current Part 50-based program for managing the effects of aging on IPEC buried piping and tanks. In that capacity, Mr. Lee was responsible for developing and implementing the UPTIMP, which Entergy also is using to implement its license renewal AMP (i.e., the BPTIP). Mr. Lee holds a B.S. degree in Mechanical Engineering from the City College of New York.

e. Mr. Stephen F. Biagiotti, Jr.

70. Mr. Biagiotti is a Senior Associate with Structural Integrity Associates, Inc. (SI) in Centennial, Colorado.170 SI is an international consulting firm that provides expert inspection, assessment, and engineering services to the nuclear, fossil, and pipeline industries, with particular focus on analyzing, preventing, and controlling structural and component failures. Mr.

Biagiotti has over twenty-five years of work experience focusing on corrosion control at pipeline, production, and refinery operations in the oil and gas industry and at operating nuclear power plants. Over the past six years at SI, he has been the technical lead in the development of corrosion engineering solutions, databases, and computer models for the assessment of buried piping to detect the degradation mechanisms of internal and external corrosion. During that time, he developed for EPRI the new nuclear industry buried piping data model and software application for Version 2 of BPWorks', and the companion Microsoft Windows-based software application, MAPPro©, which provide risk-based ranking of buried piping systems. Mr. Biagiotti has been a member of NACE International (formerly NACE) for over twenty years, and during the past five years, he has served as the Chairman of a NACE Task Group 357, which created Standard Practice 0507, External Corrosion Direct Assessment Integrity Data Exchange Format, 170 Mr. Biagiottis professional qualifications are provided in his statement of qualifications (ENT000376) and summarized in testimony. See Entergy Testimony at 6-9 (A18-20) (ENTR30373).

and he is an active leader in Task Group 404 on Nuclear Buried Piping. More recently, Mr.

Biagiotti served as chairman of Special Technology Group 35, Pipelines, Tanks and Well Casings, which is responsible for overseeing all standard development and reaffirmations on these topics. Currently, he is the Associate Technology Coordinator for the NACE Cross-Industry Technology C2 group, Corrosion Prevention and Control for Pipelines and Tanks, Industrial Water Treating and Building Systems and Cathodic Protection Technology. Mr.

Biagiotti holds B.S. and M.S. degrees in Metallurgical Engineering from the Colorado School of Mines and is a Registered Professional Engineer in Colorado. He also is NACE Cathodic Protection Level II certified.

f. Mr. Jon R. Cavallo

71. Mr. Cavallo is a Vice President and Senior Consultant with UESI Nuclear Services, specializing in corrosion mitigation and protective coatings, based in Portsmouth, New Hampshire.171 He has forty years of work experience related to corrosion mitigation and protective coatings in the nuclear industry. Mr. Cavallo is a NACE-certified Level 3 Coating Inspector (the top certification offered by the NACE International Coating Inspector Program),

with Nuclear Facilities Endorsement, and a certified SSPC (The Society for Protective Coatings)

Protective Coatings Specialist. He also holds registrations as a Certified Nuclear Coatings Engineer from the National Board of Registration for Nuclear Safety Related Coating Engineers and Specialists and Senior Nuclear Coatings Specialist from the Board of International Registration for Nuclear Coatings Specialists. In 2010, Mr. Cavallo received the ASTM International Award of Merit and the designation of Fellow. Mr. Cavallo was elected Chairman 171 Mr. Cavallos professional qualifications are provided in his statement of qualifications (ENTR00377) and summarized in his testimony. See Entergy Testimony at 9-11 (A22-24) (ENTR30373).

of the ASTM Technical Committee D-33 on Protective Coating and Lining Work for Power Generation Facilities for the periods 2003 through 2005, 2006 through 2007, and 2008 through 2009. In addition, he served as Chairman of the Industry Coating Phenomena Identification and Ranking Table Panel reviewing the work of Savannah River Technical Center on the NRC Containment Coatings Research Project (NRC Generic Safety Issue 191). In 2001, Mr. Cavallo served as Editor of EPRI Technical Report 1003120 (formerly TR-109937), Revision 1, Guideline on Nuclear Safety-Related Coatings. He also assisted in the development of, and continues to teach, an EPRI Comprehensive Coatings Course. Mr. Cavallo is also the Principal Investigator for Revision 2 to Guideline on Nuclear Safety-Related Coatings, which EPRI published as a final report in December 2009. Mr. Cavallo holds a B.S. degree in Engineering Technology from Northeastern University in Boston, Massachusetts and is a Registered Professional Engineer in three states.

72. Based on their professional backgrounds and experience, the Board finds that each of Entergys six witnesses is qualified to testify as an expert witness with respect to the issues raised in NYS-5.

2. NRC Staffs Expert Witnesses

73. The NRC Staff presented written and oral testimony by a panel of two witnesses:

(1) Mr. William C. Holston and (2) Ms. Kimberly J. Green.

a. Mr. William C. Holston Mr. Holston is a Senior Mechanical Engineer in the NRC Division of License Renewal (DLR), Office of Nuclear Reactor Regulation (NRR).172 He is responsible for conducting technical reviews of AMRs and AMPs for SSCs within the scope of license renewal for a variety 172 Mr. Holstons professional qualifications are provided in his statement of qualifications (NRC000018) and summarized in his testimony. See NRC Staff Testimony at A.1(b), A.2(b), A.3(b), A.4(b) (NRCR20016).

of materials, component types and aging effects. Mr. Holston serves as the lead DLR reviewer for buried and underground piping and tank AMPs and related issues. He has conducted reviews of these AMPs and the related AMRs for buried and underground SSCs in the LRAs for sixteen nuclear power plants. Mr. Holston provided peer review input for recent changes to NUREG-1801, Revision 2, which includes new GALL AMP XI.M41. In addition, he is the author of LR-ISG-2011-03, Changes to the Generic Aging Lessons Learned (GALL) Report Aging Management Program XI.M41 Buried and Underground Piping and Tanks, which was issued in final form in August 2012. Mr. Holston served as the Staffs principal reviewer of Entergys AMP for buried piping and tanks, including RAI responses and other related submittals. He authored the portions of the Staffs SER and SER Supplement 1 that document the Staffs review and evaluation of Entergys BPTIP for IPEC license renewal.

b. Ms. Kimberly J. Green

74. Ms. Green is a Senior Mechanical Engineer in NRRs DLR.173 She has substantial experience in conducting technical reviews of AMRs and AMPs related to auxiliary and steam and power conversion systems in LRAs. From April 2007 until April 2011, she served as the project manager responsible for the Staffs safety review of the IPEC LRA. Ms.

Green also served as a member of the Staffs audit teams that evaluated Entergys scoping and screening methodology, AMRs, and AMPs, and was principally responsible for preparing the Staffs November 2009 SER, including the section related to the IPEC BPTIP.

75. Based on their professional backgrounds and experience, the Board finds that Mr.

Holston and Ms. Green are qualified to testify as expert witnesses on the issues raised in NYS-5.

173 Ms. Greens professional qualifications are provided in her statement of qualifications (NRC000017) and summarized in her testimony. See id. at A.1(a), A.2(a), A.3(a), A.4(a).

3. New Yorks Expert Witness

76. New Yorks sole witness, Dr. David J. Duquette, provided written direct and rebuttal testimony and oral testimony at the evidentiary hearing on Contention NYS-5.

77. Dr. Duquette is a corrosion consultant and Professor of Engineering at RPI within the Department of Materials Science and Engineering.174 He holds a B.S. degree from the United States Coast Guard Academy and a Ph.D. from the Massachusetts Institute of Technology (MIT). He performed his graduate work at the Corrosion Laboratory at MIT, spent two years as a Research Associate at the Advanced Materials Research and Development Laboratory at Pratt and Whitney Aircraft before joining the faculty at RPI. Dr. Duquettes research is primarily in the area of corrosion science and engineering. Dr. Duquette is a member of the United States Nuclear Waste Technical Review Board, to which he was appointed in 2002. Dr.

Duquettes experience with corrosion issues at nuclear power plants includes consultation at Three Mile Island (TMI-1 and TMI-2), Diablo Canyon, PWRs and boiling water reactors formerly operated by Commonwealth Edison (Byron, LaSalle, Braidwood, Dresden, Quad Cities, Clinton), and Seabrook. Dr. Duquette has served on EPRI panels for corrosion control in nuclear power systems. His consulting experience includes assessing corrosion of numerous structures, including other (non-nuclear) buried structures such as oil and natural gas lines, buried tanks, and other underground infrastructure.

78. At the hearing, Dr. Duquette acknowledged that he did not have any NRC licensing or regulatory expertise or expertise in radiation physics.175 Nonetheless, based on his 174 Dr. Duquettes professional qualifications are provided in his statement of qualifications (NYS000166) and summarized in his testimony. See New York Direct Testimony at 1-3 (NYS000164).

175 Dec. 10, 2012 Tr. at 3557:19-21 (Duquette) (Im not an expert on licensing or regulation), 3564:12-14 (Duquette) (stating his opinion as a layman and a citizen, not as an expert on radiation physics); see also professional background and experience, the Board finds that Dr. Duquette is qualified to testify an as expert witnesses relative to the issues raised in NYS-5.

B. Technical Background

79. As Entergys witness panel testified, the buried and underground piping and tanks at IPEC subject to AMR include metallic components (i.e., buried carbon steel, ductile or gray cast iron, copper alloy, and stainless steel components).176 The aging effect of concern for these components is loss of material due to various forms of corrosion (i.e., general, pitting, crevice, and microbiologically-induced corrosion.).177 Specific corrosion mechanisms are discussed in greater detail in several exhibits to the parties pre-filed testimony.178 Although loss of material is a potential aging effect for both the internal and external surfaces of buried components, internal and external aging effects are addressed through different AMPs.179 As stipulated by the parties, NYS-5 focuses solely on loss of material due to external corrosion of buried components, as managed under Entergys BPTIP.180

80. Mr. Biagiotti and Mr. Cavallo explained that corrosion is largely an electrochemical phenomenon, whereby metals revert to a lower energy state (e.g., an oxide) by id. at 3564:25-3465:1 (declining to answer question regarding exceedance of radiological dose exposure limits and stating that I would not pass myself off as an expert in that area).

176 Entergy Testimony at 37 (A53) (ENTR30373) (citing LRA at 3.4-8 (ENT00015B); NUREG-1930, Vol. 1, Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3 (Nov. 2009) at 3-336, 3-372 (NUREG-1930) (NYS000326D)).

177 Id. (citing LRA at 3.4-8 (ENT00015B); NUREG-1930, at 3-336, 3-372 (NYS000326D); Final LR- ISG-2011-03, App. A at A-1, A-3 to A-4 (NRC000162)).

178 See NUREG/CR-6876, Risk-Informed Assessment of Degraded Buried Piping Systems in Nuclear Power Plants at 25-28 (June 2005) (NUREG/CR-6876) (ENT000386); CEP-UPT-0100, Rev. 0, Underground Piping and Tanks Inspection and Monitoring, Appendix A (Oct. 31, 2011) (NYS000173); Herbert H. Uhlig &

R. Winston Revie, Corrosion and Corrosion Control, An Introduction to Corrosion Science and Engineering 90-122 (John Wiley & Sons, Inc. 3d ed. 1985) (Corrosion and Corrosion Control) (ENT000387).

179 Entergy Testimony at 38 (A54) (ENTR30373).

180 See State of New York, Entergy Nuclear Operations, Inc., and NRC Staff Joint Stipulation at 1 (Jan. 23, 2012),

available at ADAMS Accession No. ML12023A110; see also New York Direct Testimony at 6:21-7:15 (NYS000164); Duquette Report at 4 (NYS000165).

electrochemical or chemical reactions.181 The corrosion process involves the removal of electrons (oxidation) of the metal and the consumption of those electrons by some other reduction reaction, such as oxygen or water reduction.182

81. Mr. Biagiotti, Mr. Cavallo, and Mr. Lee testified that corrosion of buried pipes and tanks can occur when two or more electrochemically dissimilar metals are electrically connected to each other and in physical contact with the same electrolyte (e.g., soil), such that a corrosion cell is created.183 The direction of positive current flow is from the metal with the more negative potential through the electrolyte to the metal with the more positive potential.184 The corroding metal, called an anode, is the metal from which the current leaves to enter the electrolyte.185 The metal that receives the current is referred to as the cathode.186 Corrosion thus occurs as a result of anodic reactions that take place at the point where the positive current leaves the metal surface.187 According to Mr. Biagiotti, corrosion is a very gradual process.188

82. As Mr. Biagiotti, Mr. Cavallo, and Mr. Lee testified, the degradation rate of ferrous materials in buried piping is a function of environmental, metallurgical, and hydrodynamic variables.189 For example, the rate of external degradation may be affected by 181 Entergy Testimony at 39 (A56) (ENTR30373) (citing Corrosion and Corrosion Control at 90-91 (ENT000387)).

182 Id.

183 Id. at A59. During the hearing, Mr. Biagiotti provided an overview of the corrosion process, corrosion control principles, and techniques for measuring pipe-to-earth potentials (i.e., current flows through the soil) including the close interval and direct current voltage gradient survey methods). See Dec. 11, 2012 Tr. at 3770:18-3777:7 (Biagiotti).

184 Entergy Testimony at A59 (ENTR30373).

185 Id.

186 Id.

187 Id. (citing Corrosion and Corrosion Control at 90 (ENT000387)).

188 Dec. 11, 2012 Tr. at 3741:19-25, 3791:7-9 (Biagiotti).

189 Entergy Testimony at 38 (A55) (ENTR30373) (citing NUREG/CR-6876 at 32 (ENT000386)).

aggressive chemicals (if present), temperature, oxygen content, pH, and electrochemical potentials between two metals in the soil material and groundwater (if present).190 A key metallurgical variable is the chemical composition of various elements in the pipe material that impact a stable corrosion resistant surface oxide film (e.g., weight percentage of chromium, nickel, and copper) and the resistance of those elements to further oxidation.191

83. Mr. Biagiotti and Mr. Cavallo stated that for external corrosion to be likely in a buried piping application, a susceptible material (e.g., carbon steel) must be in contact with a corrosive environment (i.e., soil) to support a corrosion reaction.192 But as Mr. Biagiotti, Mr.

Cavallo, and Mr. Lee pointed out, not all soils are corrosive.193 Soil corrosivity depends on the interaction of multiple parameters, including soil moisture content, soil type, soil pH, and soluble salt content (e.g., Na+, Cl-, and SO42-).194

84. Mr. Biagiotti and Mr. Cavallo explained that these soil parameters may be observed or measured directly.195 Soil resistivity testing is a method commonly used to measure the degree to which the soil opposes an electric current passing through it.196 Highly resistive soil contains minimal water, large fractions of sand (which create discontinuities, i.e., voids, in the soil), or rock, which limits the electrolytic capabilities of the soil, thereby inhibiting current 190 Id. at 38-39 (A55) (citing Corrosion and Corrosion Control at 91-114 (ENT000387); CEP-UPT-0100, Rev. 1, App. A (ENT000598)).

191 Id. at 39 (A55) (citing Corrosion and Corrosion Control at 91-114 (ENT000384)).

192 Id. at 39-40 (A57).

193 Id. at 39-40 (A57), 42 (A60).

194 Id. at 39 (A57); Dec. 11, 2012 Tr. at 3718:21-3719:14 (Biagiotti).

195 Entergy Testimony at 39-40 (A57) (ENTR30373) (citing NACE SP0169-2007, Standard Practice - Control of External Corrosion on Underground or Submerged Metallic Piping Systems (Mar. 15, 2007) (NACE SP0169-2007) (ENT000388); S.F. Biagiotti, Jr., et al., Using Soil Analysis and Corrosion Rate Modeling to Support ECDA and Integrity Management of Pipelines and Buried Plant Piping, NACE Corrosion/2010, Paper 10059 (Mar. 2010) (NACE Paper 10059) (ENT000389)).

196 Id. at 40 (A58); Dec. 11, 2012 Tr. at 3719:24-3720:8 (Biagiotti).

flow and impeding corrosion.197 Soil resistivity values are typically stated in terms of ohm-cm, with values exceeding 10,000 ohm-cm typically considered only mildly corrosive to essentially non-corrosive.198 Soil resistivity is one indicator of corrosion potential for buried structures and must be integrated into the overall corrosion assessment using the other considerations described above.199

85. As Mr. Biagiotti, Mr. Cavallo, and Mr. Lee testified, the fundamental principle in corrosion control is preventing a susceptible material from coming in contact with a corrosive environment.200 Thus, protective coatings applied to the external surfaces of buried pipes provide the primary form of corrosion control.201 Such coatings form a moisture and chemical-resistant barrier that is bonded to the outer surface of the pipe and thereby creates a barrier between the soil and the pipe.202 External coatings effectively perform the function of isolating piping from a corrosive environment, so that no corrosion occurs.203

86. Mr. Biagiotti, Mr. Cavallo, and Mr. Lee further testified that cathodic protection is a secondary corrosion control technique used to inhibit corrosion when bare material becomes exposed to the surrounding soil.204 The technique prevents corrosion by converting the anodic or active sites on the metal surface of buried pipe to a cathodic or passive state by supplying 197 Entergy Testimony at 40 (A58) (ENTR30373).

198 Id.

199 Id. (citing NACE SP0169-2007 (ENT000388); NACE Paper 10059 (ENT000389)).

200 Entergy Testimony at 42 (A60) (citing NACE SP0169-2007 (ENT000388); NACE Paper 10059 at 1-2 (ENT000389)).

201 Id.; see also Dec. 11. 2012 Tr. at 3858:20-24 (Holston) ([T]he coatings are the primary means of protecting the piping.).

202 Entergy Testimony at 42 (A60) (ENTR30373).

203 Id.

204 Id. at 44 (A61). A detailed discussion of cathodic protection theory as applied to buried piping is contained in A.W. Peabody, Peabodys Control of Pipeline Corrosion at 21-48 (2d ed. 2001) (Peabodys Control of Pipeline Corrosion) (ENT000390).

electrical current via an anode.205 Cathodic protection may be necessary to prevent corrosion of buried piping when its coating has degraded and exposed the metallic surface of the piping to a corrosive environment.206 If the coating applied to buried piping is still effective, then cathodic protection is not necessary to prevent external corrosion of the piping and will offer no addition corrosion control.207 Therefore, cathodic protection systems are only required, or effective, when supplemental corrosion protection is needed at localized areas of coating degradation in corrosive soil environments.208 We discuss the use of cathodic protection at IPEC in Section IV.H, infra.

C. The IPEC BPTIP Is Consistent with the Applicable NUREG-1801 (GALL Report)

Recommendations and Appropriately Documented in the LRA

1. NUREG-1801 sets forth the NRC Staffs approved recommendations for aging management of in-scope buried and underground piping.

87. As discussed in Section III.C above, specific guidance concerning the AMPs that the NRC Staff considers acceptable is provided in NUREG-1801, or the GALL Report (NYS00146A-C). NUREG-1801 contains the NRCs approved set of recommendations as applicable for the component and material type, the environment to which the items are exposed (e.g., raw water, soil, outdoor air), and the aging effect which is being managed.

88. At the time Entergy filed its LRA in April 2007, the relevant GALL AMP for managing external corrosion of buried piping without cathodic protection was described in 205 Entergy Testimony at 41 (A59) (ENTR30373).

206 Id. at 44 (A61) (citing NACE SP0169-2007 (ENT000388); NACE Paper 10059 at 2 (ENT000389)).

207 Entergy Testimony at 44 (A61) (ENTR30373).

208 Id.

Section XI.M34 of NUREG-1801, Rev. 1.209 Among other key elements, GALL AMP XI.M34 included reliance on preventive measures (i.e., protective coatings on buried piping) to mitigate external corrosion and (2) inspections to manage the effects of corrosion on the pressure-retaining capability of buried piping.210

89. In December 2010, the NRC Staff issued NUREG-1801, Rev. 2.211 It contained a new GALL AMP XI.M41, Buried and Underground Piping and Tanks, which the Staff developed based on industry operating experience that occurred before and during the development of NUREG-1801, Rev. 2. GALL AMP XI.M41 replaced two AMPs contained in NUREG-1801, Rev. 1: AMP XI.M28, Buried Piping and Tanks Surveillance (which applied to plants with cathodic protection systems) and AMP XI.M34, Buried Piping and Tanks Inspection.212

90. New GALL AMP XI.M41 reinforced the importance of preventive actions, including cathodic protection, coatings, and backfill quality.213 The number of recommended inspections in AMP XI.M41 was increased from the number recommended in AMPs XI.M28 and XI.M34 and linked to the material type, system function, and degree to which the preventive actions were applied.214 Additionally, AMP XI.M41 addressed unique requirements based on 209 NUREG-1801, Vol. 1, Rev. 1, Generic Aging Lessons Learned (GALL Report) at XI M-111 to XI M-112 (Sept. 2005) (NUREG-1801, Rev. 1) (NYS00146C); Dec. 11, 2012 Tr. at 3934:13-15 (Holston) (stating that Entergy referenced NUREG-1801, Rev. 1, AMP XI.M34 in its LRA).

210 NUREG-1801, Rev. 1 at XI M-111 (NYS000146C).

211 NUREG-1801, Rev. 2 (NYS00147A-D).

212 Entergy Testimony at 24 (A41) (ENTR30373).

213 Id. (citing NUREG-1801, Rev. 2 at XI M41-1 to XI M41-3 (NYS00147D)).

214 Id. (citing NUREG-1801, Rev. 2 at XI M41-4 to XI M41-10 (NYS00147D)).

whether the piping and tanks were buried (direct contact with soil or concrete) or underground (below grade, located in a limited access area, and exposed to air).215

91. In March 2012, the NRC Staff issued Draft LR-ISG-2011-03, Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management Program XI.M41, Buried and Underground Piping and Tanks (Mar. 2012) (ENT000379 and NRC000019). As stated therein, based on its review of numerous LRAs and stakeholder feedback, the Staff decided to revise GALL AMP XI.M41 to, among other things, include inspection recommendations for plants not using site-wide cathodic protection systems during the PEO; add a recommendation related to extent of condition evaluations for situations involving significant coating damage caused by non-conforming backfill; add the specific preventive and mitigative actions utilized by the AMP in the UFSAR Supplement description of the program.216 The NRC requested public comments on Draft LR-ISG-2011-03 in March 2012.

92. After considering public and internal Staff comments, the NRC issued Final LR-ISG-2011-03 in August 2012. Final LR-ISG-2011-03 made a number of revisions to GALL AMP XI.M41 and explains the bases for those changes. For example, it revised GALL AMP XI.M41 Table 4a, Inspections of Buried Pipe, to reflect the recommended number of inspections when cathodic protection will not be provided during the PEO for systems or portions of systems within the scope of license renewal.217 Given that licensees risk rank their 215 NUREG-1801, Rev. 2 at XI M41-2 to XI M41-11 (NYS00147D).

216 Draft License Renewal Interim Staff Guidance, LR-ISG-2011-03, Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management Program XI.M41, Buried and Underground Piping and Tanks at 1-2 (Mar. 9, 2012) (ENT000379).

217 Final LR-ISG-2011-03 at 3 (NRC000162). For a two-unit site that does not have cathodic protection and has plant-specific operating experience involving debris in the backfill and coating damage, Table 4a of Final LR-ISG-2011-03 (NRC000162) recommends twenty-three (23) inspections in the ten years prior to the period of PEO, thirty (30) inspections in the first ten years of the PEO, and thirty-eight (38) inspections the second ten years of the PEO (a total of ninety-one (91) inspections).

inspection locations based on the potential for and consequence of failure, the Staff also revised Table 4a to combine the code class/safety-related and hazardous material piping inspection columns into one inspection category. Appendix A to Final LR-ISG-2011-03 contains the revised (and current) version of GALL AMP XI.M41, which reflects these and other changes to that AMP and supersedes the version of GALL AMP XI.M41 issued in December 2010. 218

2. The IPEC BPTIP is consistent with NUREG-1801, Rev. 1, AMP XI.M34.

93. As stated previously, in its April 2007 LRA, Entergy committed to NUREG-1801, Rev. 1, AMP XI.M34, without exception.219 Therefore, its AMP for buried piping and tanks was written to be consistent with the 2005 version of NUREG-1801 (i.e., Revision 1).220 Mr. Cox testified that the original BPTIP program description indicates that the IPEC program was, in essence, the exact program that the NRC Staff had reviewed and approved in NUREG-1801, Revision 1.221 Therefore, the details of the ten-element NUREG-1801 program XI.M34 description (e.g., inspection methods, acceptance criteria, and corrective actions) were incorporated by reference into the IPEC LRA and constituted the AMP.222 218 Final LR-ISG-2011-03 at 1 & app. A at A-6 to A-8 tbl. 4a. (NRC000162) (footnotes 2E and 2F).

219 Entergy Testimony at 23 (A41) (ENTR30373).

220 LRA, app. B at B-27 (ENT00015B); NUREG-1801, Rev. 1 at XI M-111 to XI M-112 (NYS000146C).

221 Dec. 10, 2012 Tr. at 3313:18-22 (Cox) (We consider the GALL a program to be an [AMP] described in terms of the ten elements that are specified in the standard review plan.); id. at 3315:10-19 (Cox) ([T]he GALL Report documents the Staffs review of that program which has been found effective throughout the industry in terms of operating experience to be able to manage the effects of aging that its designed to manage. By showing that we have or even citing the same program, thats a demonstration that we used to say would be an effective program. Its the same program thats been found effective at other sites in other license renewal application reviews.); id. at 3323:3-5 (Holston) (An AMP within the GALL report such as AMP XI.M34 is an approved set of recommended ways to manage the aging.).

222 Id. at 3317:19-25, 3318:5-10 (Cox) (stating that the GALL Report AMP contains details regarding inspection methods, acceptance criteria, and corrective actions); see also id. at 3321:7-15 (Holston) (stating that the ten GALL AMP elements are recommended actions that the applicant can take to create an acceptable program at the site); id. at 3346:7-11 (Were making a commitment as part of the license renewal application to implement the program that described in B.1.6 which by reference incorporates the elements of the GALL program.); id. at 3347:6-8 (During the [PEO], we intend to do everything that's defined by those ten elements as described in the GALL report.).

94. Mr. Holston testified that the NRC Staff verified that Entergys BPTIP was consistent with NUREG-1801, Rev. 1, AMP XI.M34 through the AMP audit process.223 For example, during its onsite audit of the BPTIP, the Staff reviewed onsite documentation supporting the LRA to verify consistency of the BPTIP with the corresponding NUREG-1801 program, and to confirm that IPEC plant-specific conditions were bounded by the conditions for which the NUREG-1801 program was evaluated.224 New York and Dr. Duquette did not dispute Entergys claim that the BPTIP is consistent with NUREG-1801, Rev. 1, AMP XI.M34.

3. Entergy substantially revised the IPEC BPTIP to reflect recent operating experience and to be consistent with the NRC Staffs key recommendations in NUREG-1801, Rev. 2, AMP XI.M41.

95. As a result of industry and IPEC operating experience, related industry and Entergy fleet initiatives, and NRC Staff license renewal RAIs, Entergy significantly revised the BPTIP in 2009 and 2011. The first major revision is documented in a July 27, 2009, submittal to the NRC (as later clarified in another submittal dated August 6, 2009).225 This revision to the BPTIP incorporated risk-ranking of inspection locations based on the potential consequences of leakage and the potential for corrosion, as recommended by the EPRI in Recommendations for an Effective Program to Control the Degradation of Buried and Underground Piping and Tanks (1016456, Revision 1) (NYS000167).226 In revising the BPTIP, Entergy significantly increased 223 Id. at 3331:13-16 (Holston), 3331:23-3332:1 (Holston), 3409:20-25 (Green), 3440:17-23 (Holston).

224 See Audit Report for Plant Aging Management Programs and Reviews for Indian Point Nuclear Generating Units Nos. 2 and 3 at 8-9 (Jan. 13, 2009) (ENT000041). SER at 3-15 to 3-18 (NYS00326B); Dec. 11, 2012 Tr.

at 3678:9-3680:2 (Green) (describing BPTIP audit process).

225 NL-09-106 (NYS000203); NL-09-111, Letter from F. Dacimo, Entergy to NRC Document Control Desk (Aug.

6, 2009) (NL-09-111) (NYS000171).

226 NRC Staff Testimony at 38 (A31) (NRC20016).

the number of inspections to be completed before IP2 and IP3 entered the PEO.227 The NRC Staffs evaluation of the BPTIP, as revised in 2009, is documented in the Staffs SER, issued in November 2009.228

96. Subsequent to issuance of the SER in November 2009, the NRC Staff issued RAIs to current license renewal applicants concerning their plans to address recent industry buried piping operating experience.229 In response to these RAIs, Entergy further revised the BPTIP, providing more specificity on its planned inspection methods (i.e., excavated direct visual examinations of buried piping), and committed to conduct additional inspections prior to the PEO and during each of the ten-year periods during the twenty-year PEO.230 The Staffs evaluation of these responses and the Applicants changes to the BPTIP are documented in SER Supplement 1, issued in August 2011.231

97. As a result of these BPTIP revisions, Entergy committed to perform ninety-four (94) excavated direct visual inspections, as follows: thirty-four (34) excavated direct visual examinations of in-scope buried piping prior to the PEO and thirty (30) excavated direct visual examinations of in-scope buried piping during each ten-year period during the twenty-year 227 See NL-09-111, Attach. 1 at 1 (NYS000171). Entergy committed to conduct fifteen (15) periodic inspections for IP2 prior to entering the PEO operation in 2013, and thirty (30) periodic inspections for IP3 prior to entering the period of PEO in 2015.

228 See SER at 3-13 to 3-18 (NYS00326B) 229 See Dec. 11, 2012 Tr. at 3934:13-3935:8 (Holston). As discussed at hearing, industry operating experience in the 2009-2010 frame, including a 2009 leak from the IP2 condensate storage tank return line, prompted the NRCs revision of the GALL Report AMP for buried piping. Dec. 10, 2012 Tr. at 3369:24-3370:8 (Holston).

230 Entergy Testimony at 53 (A75) (ENTR30373); see also Dec. 10, 2012 Tr. at 3318:11-17 (Cox) (noting substantial revisions to the IPEC BPTIP in response to NRC Staff RAIs and advancements in industry knowledge).

231 SER Supp. 1 at 3-1 to 3-2 (NYS000160); Dec. 10, 2012 Tr. at 3388:9-17 (Holston) (stating that the Staff did a gap analysis between NUREG-1801, Rev. 1 and NUREG-1801, Rev. 2, issued RAIs to Entergy, and evaluated Entergys revised AMP in the SER Supplement against current Staff recommendations in NUREG-1801, Rev.

2); Dec. 11, 2012 Tr. at 3681:19-23 (Holston).

PEO.232 Collectively, these ninety-four (94) inspections will include full circumferential inspections of over 900 linear feet of in-scope buried piping.233

98. Additionally, Entergy committed to conduct soil sampling and testing to evaluate soil corrosivity before entering the PEO and once during each ten-year period during the twenty-year PEO using industry standard soil testing parameters and corrosivity determination guidance.234 Entergy has committed to collect soil samples at a minimum of two locations near in-scope piping to determine representative soil conditions.235 The soil parameters to be analyzed include moisture, pH, chlorides, sulfates, and resistivity.236 Based on the American Water Works Association (AWWA) Standard C105 (NRC000028), these parameters are sufficient to determine the corrosivity of the soil.237 Entergy also has committed to increase the number of inspections beyond the baseline number by twenty-four (24) inspections, if the soil samples indicate that the soil is corrosive.238

99. On November 29, 2012, Entergy revised the BPTIP, this time to reflect its identification of approximately 270 feet of piping that meets the definition of underground 232 Entergy Testimony at 64 (A84) (ENTR30373).

233 NRC Staff Testimony at 39 (A31) (NRCR20016). These ninety-four excavated direct visual inspections of in-scope buried piping are in addition to the similar inspections that Entergy will perform on coated, carbon steel buried piping that is not in-scope for license renewal under Entergys 10 C.F.R. Part 50 program, the UPTIMP.

Dec. 11, 2012 Tr. at 3863:7-11 (Azevedo). As Mr. Lee explained, the results of all inspections are factored into the inspection planning process. Id. at 3864:13-20 (Lee).

234 NRC Staff Testimony at 40 (A31) (NRCR20016).

235 Id. During the hearing, Dr. Duquette suggested that Entergys proposed soil sampling protocol is inadequate because it envisions taking soil samples within the top three feet of soil, which is likely to be backfill. Dec. 10, 2012 Tr. at 3431:5-15, 3431:17-3432:11 (Duquette). However, the BPTIP states: Soil will be tested at a minimum of two locations at least three feet below the surface near in-scope piping to determine representative soil conditions for each system. NL-12-174, Attach. 2 at 1 (ENT000597). Mr. Cox confirmed that Entergy will take soil samples at whatever depth it needs to be, to be adjacent to the piping thats concerned. Dec.

10, 2012 Tr. at 3495:13-17 (Cox).

236 NRC Staff Testimony at 39 (A31) (NRCR20016); Dec. 11, 2012 Tr. at 3719:2-8 (Biagiotti).

237 NRC Staff Testimony at 39 (A31) (NRCR00016).

238 Id.; Dec. 10, 2012 Tr. at 3450:16-17 (Holston); Dec. 11, 2012 Tr. at 3633:19-3634:10 (Holston).

piping in NUREG-1801, Rev. 2, AMP XI.M41.239 As noted above, NUREG-1801, Rev. 2 defines underground piping as piping that is below grade and contained within a tunnel or vault, such that the piping is in contact with air and access for inspection is restricted.240 The term restricted is not explicitly defined in NRC license renewal guidance documents.241 Therefore, on October 11, 2012, Entergy held a conference call with the NRC Staff to clarify the definition of restricted as used in NUREG-1801, Rev. 2 and the Final ISG.242 During the call, the NRC Staff clarified that it intended restricted to refer to piping that is located in vaults for which access requires more than simply opening a locked access cover.243 100. As a result of this recent clarification, Entergy identified portions of the service water, city water, and fuel oil systems that are located in vaults that require more than unlocking a hatch or cover for access.244 This piping is now considered to be underground piping as defined in NUREG-1801, Rev. 2 and Final LR-ISG-2011-03.245 Specifically, this piping includes portions of two 24-inch diameter IP3 service water inlet headers (approximate total length of seventy feet) that run over the discharge canal, portions of the Indian Point 2 and 3 fuel oil piping (1 1/2-inch, 3-inch and 4-inch in diameter) that supply and run between the fuel oil storage tanks and from the storage tanks to each of the emergency diesel generator (EDG) rooms (approximate total length of 160 feet) and a portion of the 3/4-inch diameter IP3 city water 239 See NL-12-174, Attach. 2 at 1-4 (ENT000597).

240 Entergy Testimony at 25 (A43) (ENTR30373) (citing Final LR-ISG-2011-3, App. A at A-1 (NRC000162)).

241 Id. at 28 (A46).

242 See Summary of Telephone Conference Call Held on October 11, 2012 Between the U.S. Nuclear Regulatory Commission and Entergy Nuclear Operations, Inc., Concerning the Indian Point Nuclear Generating Unit Nos.

2 and 3, License Renewal Application (Oct. 31, 2012) (ENT000595).

243 Entergy Testimony at 29 (A46) (ENTR30373).

244 NL-12-149 at 1-2 (ENT000596).

245 Id. at 1.

piping (approximate total length of forty feet) that runs in the EDG pipe trench.246 This in-scope piping previously was treated as accessible piping (as opposed to restricted-access piping) subject to aging management under the IPEC External Surfaces Monitoring Program.247 101. Entergy revised the BPTIP (and added new Commitment No. 48) to commit to visually inspect IPEC underground piping within the scope of license renewal and subject to AMR prior to the PEO and then on a frequency of at least once every two years during the PEO.248 Entergy also committed to maintain this inspection frequency (at least once every two years) unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by Final LR-ISG-2011-03.249 Entergy further committed to supplement visual examinations with surface or volumetric non-destructive testing if indications of significant loss of material are observed, and to enter such adverse indications into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).250 102. Mr. Holston testified that because Entergy has committed to inspect all in-scope underground piping prior to the PEO and to inspect all in-scope underground piping at least once every two years and to take further action if appropriate, there is reasonable assurance that the intended function of the underground piping will be met throughout the PEO.251 246 Id. at 1-2.

247 Entergy Testimony at 29 (A46) (ENTR30373).

248 Id. at 61 (A80) (citing NL-12-174 at 1 & Attach. 1 at 21 (ENT000597)).

249 NL-12-174 at 1 (ENT000597).

250 Id.

251 NRC Staff Testimony at 24 (A18) (NRCR20016).

103. Subsequent to the hearing, on March 5, 2013, Entergy filed a letter (NL-13-037) with the NRC that revised Entergys March 28, 2011 responses to parts la, 1b and 1c of NRC Staff RAI 3.0.3.1.2-1, as set forth in NL-11-032 (NYS000151).252 The revisions made to those RAI responses are consistent with recommendations in Final LR-ISG-2011-03 (NRC000162).253 As explained in NL-13-037, Entergys March 28, 2011 RAI responses reflected recommendations contained in the December 2010 version of NUREG-1801, Rev. 2 Section XI.M41, Table 4a (see NYS00147D), which distinguished between Code Class/Safety-Related and Hazmat buried piping in specifying the numbers of recommended direct visual inspections.254 In the Final LR-ISG-2011-03, the NRC Staff revised NUREG-1801, Rev. 2,Section XI.M41, Table 4a (see NRC000162) to combine Code Class/Safety-Related and Hazmat categories into a single category (In-Scope Piping) to allow licensees to select inspection locations based on plant-specific risk ranking rather than piping categories.255 Accordingly, NL-13-037 revised the above-referenced RAI responses in NL-11-032 to conform to the current 252 See NL-13-037, Letter from F. Dacimo, Vice President, Entergy, to NRC Document Control Desk, Revision to the Response to Request for Additional Information (RAI) Aging Management Programs (Mar. 5, 2013)

(NL-13-037) (ENT000606). Entergy notified the Board and parties of the submittal of NL-13-037 by letter dated March 15, 2013. See Letter from K. Sutton and P. Bessette, Morgan, Lewis & Bockius LLP, to Administrative Judges, Re: Board Notification Concerning Entergy Letter NL-13-037 (Mar. 15, 2013) (Board Notification), available at ADAMS Accession No. ML13074A785. Subsequently, on March 20, 2013, Entergy filed an unopposed Motion for Leave requesting that the Board admit NL-13-037 (ENT000606) into evidence. See Entergys Motion for Leave to File, and Request the Admission of, Two New Hearing Exhibits Related to Contention NYS-5 (Buried Piping). Entergy also requested that the Board admit into evidence a Joint Declaration (ENT000607) prepared by three of Entergys witnesses. See Joint Declaration of Nelson Azevedo, Alan Cox, and Ted Ivy Concerning Entergy Letter NL-13-037 and Related Updates to Entergys Testimony on Contention NYS-5 (Buried Piping) (Mar. 20, 2013) (March 2013 Joint Declaration). The March 2013 Joint Declaration described the purpose of NL-13-037, updated limited portions Entergys testimony that were affected by the issuance of NL-13-037, and indicated that Entergy had completed six additional direct visual inspections of IP2 in-scope buried piping in the IP2 transformer yard that were ongoing at the time of the hearing. See id. at ¶¶ 6-14. On March 22, 2013, the Board granted Entergys Motion for Leave and admitted exhibits ENT000606 and ENT000607 into evidence. Licensing Board Order (Granting Entergys Motion for Leave to File Two Hearing Exhibits) (Mar. 22, 2013) (unpublished).

253 NL-13-037 at 2 (ENT000606).

254 Id. at 1.

255 Id.

inspection recommendations in NUREG-1801, Rev. 2 Section XI.M41, Table 4a, as modified by Appendix A to Final LR-ISG-2011-03 (NRC000162).256 104. As stated in NL-13-037, the revised RAI responses do not affect the BPTIP descriptions provided in the IP2 and IP3 UFSAR Supplements, as contained in LRA Sections A.2.1.5 and A.3.1.5.257 Nor do they affect any related Entergy commitments (Commitment Nos.

3 and 48) reflected in those LRA sections and Entergys List of Regulatory Commitments.258 105. Therefore, there is no change to the total number of excavated direct visual inspections that Entergy has committed to perform before and during the PEO, or to Entergys use of the risk-ranking process described in the UFSAR Supplements (NL-12-174, Attach. 2) and fleet procedures discussed below.259 There also is no effect on the Staffs conclusion in SER, Supplement 1 (NYS000160) that Entergy is performing a sufficient number of risk-informed inspections.260 106. As discussed above, Entergy submitted its LRA before the issuance of NUREG-1801, Rev. 2, AMP XI.M41 in December 2010. Nonetheless, through the RAIs mentioned above, the Staff evaluated the BPTIP against key elements of AMP XI.M41 and then-draft LR-ISG-2011-03 (e.g., number of inspections, soil sampling, and use of plant-specific operating experience), and concluded that Entergys BPTIP, as revised, is adequate to manage the applicable aging effects to ensure that buried piping and tanks will perform their CLB functions.261 256 Id. at 2.

257 See id.; NL-12-174, Attach. 2 (ENT000597).

258 See NL-12-174 Attachs. 1 & 2 (ENT000597); March 2013 Joint Declaration at ¶ 8 (ENT000607).

259 March 2013 Joint Declaration at ¶ 9 (ENT000607).

260 Id.

261 NRC Staff Testimony at 12 n.3 (A8) (NRCR20016).

107. In this regard, Mr. Holston and Mr. Cox testified that Entergys current BPTIP the net result of the revisions discussed abovefar exceeds the recommendations in NUREG-1801, Rev. 1, AMP XI.M34, and meets the intent of the new AMP described in Section XI.M41 of NUREG-1801, Rev. 2.262 108. The Board agrees with this conclusion. The number of excavated direct visual inspections that Entergy has committed to perform under the BPTIP is consistent with the recommendations set forth in NUREG-1801, Rev. 2, AMP XI.M41 (as revised by the Final LR-ISG-2011-03 in August 2012).263 Entergy has committed to perform a minimum of 94 total excavated direct visual inspections of in-scope buried piping, which exceeds the number (91) recommended in AMP XI.M41 for a two-unit site without site-wide cathodic protection and IPECs plant-specific operating experience.264 109. As noted above, Entergy also is risk-ranking the inspection locations based on the potential for corrosion and the consequences of leakage,265 and has committed to collect and analyze additional soil samples to confirm that the soil conditions in the vicinity of in-scope buried pipes are non-aggressive.266 If the required soil testing discussed above identifies corrosive conditions, then Entergy has committed to increase the number of direct examinations 262 See Entergy Testimony at 68 (A88) (ENTR30373) (The revised program far exceeds the recommendations of NUREG-1801, Rev. 1, and clearly meets the intent of the new AMP described in Section XI.M41 of NUREG-1801, Rev. 2 issued in December 2010.); NRC Staff Testimony at 60-61 (A52) (NRCR20016) (Based on its review of the revised buried piping and tanks AMP, the Staff determined that Entergys AMP for buried piping and tanks far exceeds the recommendations in GALL AMP XI.M34 (Exhibit NYS00146A-C), and would satisfy AMP XI.M41 in GALL Report Revision 2. . . . .).

263 See Final LR-ISG-2011-03, App. A (NRC000162); Dec. 10, 2012 Tr. at 3337:1-7 (Holston) (noting NRC Staff review of AMP against Final LR-ISG-2011-03 recommendations and issuance of SER supplement).

264 Dec. 10, 2012 Tr. at 3450:15-16 (Holston); see also Dec. 11, 2012 Tr. at 3632:10-3633:4 (explaining why the Staff views 94 excavated direct visual inspections of IPEC in-scope buried piping to be an adequate number).

265 Dec. 10, 2012 Tr. at 3457:20-3460:23 (Lee).

266 NRC Staff Testimony at 33 (A29) (Holston, Green) (NRCR00016).

as specified in the revised BPTIP.267 These actions also are consistent with the Staffs position in Final ISG-LR-ISG-2011-03.268

4. The IPEC BPTIP is adequately documented in the LRA.

110. At the hearing, the Board questioned the witnesses about where the BPTIP is documented in the LRA and whether the program description in the LRA provides sufficient information for review.

111. Mr. Cox testified for Entergy that both Appendices A and B of the LRA contain a description of the program.269 Appendix A of the LRA provides the information to be submitted in an UFSAR, as required by 10 C.F.R. § 54.21(d). Appendix B provides descriptions of the AMPs and activities for the PEO.270 LRA Sections A.2.1.5 (IP2) and A.3.1.5 (IP3) are the Appendix A Sections that discuss the BPTIP.271 112. In responding to the NRC Staff RAIs discussed above, Entergy updated the IP2 and IP3 UFSAR Supplements in 2011.272 As revised, LRA Sections A.2.1.5 and A.3.1.5 explicitly address the following key elements of the BPTIP:

• the use of preventive measures that are in accordance with standard industry practice for maintaining external coatings and wrappings;

• the number and frequency of excavated direct visual inspections of IP2 and IP3 in-scope buried piping;

• evaluation of the need for additional inspections, alternate coatings, or replacement of piping if trending within the corrective action program identifies susceptible locations or areas with a history of corrosion issues; 267 See id.

268 See NRC Staff Testimony at 39 (A31) (NRCR00016).

269 Dec. 10, 2012 Tr. at 3462:2425 (Cox).

270 Id. at 3340:10-16 (Cox).

271 LRA, app. A at A-19, A-46 (ENT00015B).

272 Entergy Testimony at 53 (A75) (ENTR30373) (citing NL-09-106, Attach. 1 at 3 (NYS000203)); NRC Staff Testimony at 45-47 (A36) (NRCR20016).

• the conduct of additional soil sampling and testing before and during the PEO; and

• the need to perform twenty (20) additional excavated direct visual inspections of in-scope buried piping during each ten-year period of the PEO if soil test results indicate corrosive soil conditions.273 113. In SER Supplement 1, the NRC Staff stated that the UFSAR supplement establishes the number and frequency of piping inspections and soil testing licensing basis for the program.274 Mr. Holston elaborated on this point at hearing. Specifically, he explained that the principal bases for the Staffs acceptance of the IPEC BPTIP are captured in the UFSAR supplement, to ensure that there is a regulatory link to the requisite BPTIP activities, and that Staff is informed of changes to those activities.275 In this regard, Mr. Holston confirmed that the 10 C.F.R. § 50.59 process applies to the UFSAR descriptions of the IPEC BPTIP, including the risk ranking methodology and the number of planned inspections,276 and provides adequate controls to ensure that Entergy does not reduce the efficacy of the program.277 The requirements of 10 C.F.R. § 50.59 continue to apply to any renewed license.278 Thus, Entergys planned 273 Entergy Testimony at 53 (A75) (ENTR30373); NRC Staff Testimony at 45-47 (A36) (NRCR20016).

274 SER, Supp. 1 at 3-5 (NYS000160); see also Dec. 10, 2012 Tr. at 3329:15-22 (Holston) ([F]or example, in the case of buried pipe, they have to do a risk assessment. They have to test the soil. The number of inspections that must be done are in the UFSAR in other details. So thats how we assure that going forward into the period of extended operation those most important characteristics of the program are controlled. And the Staff is aware if they are changed.); id. at 3446:8-13 (Holston) (The additional inspections will be in locations with aggressive soil condition. There is no ambiguity there. There is no ambiguity on the quantity of inspections they have to do. That is also captured in the UFSAR supplement.).

275 Id. at 3476:13-17 (Holston); see also id. at 3542:20-22 (Holston) (But it is absolutely essential that the key aspects of that program are captured in UFSAR supplement in LRA Appendix A.).

276 Id. at 3334:13-3335:9 (Holston) (discussing the 10 C.F.R. § 50.59 process as applicable to the BPTIP).

277 Id. at 3335:10-18 (Holston).

278 In accordance with the provisions of 10 C.F.R. §§ 50.59(c), 50.71(e), and 54.21(d), information that is included in the IP2 and IP3 UFSAR Supplements becomes part of the CLB and, as noted above, cannot be revised by Entergy without it performing an evaluation in accordance with 10 C.F.R. § 50.59. In addition, pursuant to 10 C.F.R. § 50.59(d)(2), Entergy is required to maintain a record and to inform the Staff of any changes to the UFSAR or UFSAR Supplement made pursuant to 10 C.F.R. § 50.59. See Entergy Testimony at 82 (A101)

(ENTR30373); Dec. 11, 2012 Tr. at 3942:10-3943:14 (Azevedo).

buried piping inspections are enforceable and part of the IPEC licensing basis by virtue of their inclusion in the UFSAR Supplement.279 114. In a related vein, Mr. Cox stated that the aging management activities required by the BPTIP also are reflected in Entergys commitments.280 Specifically, the essential elements of the IPEC BPTIP have been included in formal license renewal commitments: Commitment No.

3 and Commitment No. 48.281 Commitment No. 3, which the Staff found acceptable in SER Supplement 1,282 states that Entergy will implement the IPEC BPTIP as described in LRA Section B.1.6, and that this new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M34. It further states that BPTIP will include a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakage and the conditions affecting the risk for corrosion.283 Commitment No. 3 also states that Entergy will establish inspection priorities and frequencies for periodic 279 Cf. Private Fuel Storage, L.L.C. (Indep. Spent Fuel Storage Installation), CLI-03-8, 58 NRC 11, 21 (2003)

(rejecting the intervenors assertion that the Board should have combined the applicants various commitments regarding soil-cement testing into a set of license conditions, stating that those commitments are set forth in

[the applicants] Safety Analysis Report and are therefore already part of the licensing basis of the facility).

280 Dec. 10, 2012 Tr. at 3341:21-3342:4 (Cox) (We would have to go to our commitments. It says were going to do a program thats consistent with the GALL M.34. The commitment also includes some of the additional actions that were committed to do. They go above and beyond what as in M.34 and GALL Rev 1. I think the commitment is what I would say demonstrates that were going to meet and effectively manage the effects of aging.).

281 See NL-12-174, Attach. 1 at 2 (Commitment #3), 21 (Commitment #48) (ENT000597). Dec. 10, 2012 Tr. at 3329:8-12 (Holston) (We take the most critical aspects of the program and ensure that they are in a document that requires the applicant to take licensing action. And thats the [UFSAR].); Dec. 11, 2012 Tr. at 3649:1-20 (Green).

282 SER, Supp. 1, at 3-5 & app. A at A-2 (NYS000160); Dec. 10, 2012 Tr. at 3354:18-22 (Cox) (The license commitment is to implement the program described in LRA Section B.1.6 which by reference to GALL Section M-1.34 makes those ten elements of that program a license renewal commitment.).

283 SER, Supp. 1, app. A at A-2 (NYS000160).

inspections of in-scope piping and tanks based on the results of the risk assessment.284 Finally, it states that Entergy will perform inspections using techniques with demonstrated effectiveness.285 115. Commitment No. 48 states that Entergy will visually inspect IPEC underground piping within the scope of license renewal and subject to AMR prior to the PEO and then on a frequency of at least once every two years during the PEO.286 116. The text of Commitment Nos. 3 and 48 is included in the IP2 and IP3 UFSAR Supplements (i.e., LRA Sections A.2.1.5 and A.3.1.5).287 Therefore, these commitments must be incorporated into the IP2 and IP3 FSARs in accordance with 10 C.F.R. §§ 50.59 and 50.71(e),

thereby becoming part of the plants current licensing bases.288 In responding to Board questions, Mr. Holston asserted that such commitments also provide a regulatory hook for NRC inspection teams to verify program implementation and take appropriate enforcement action, if necessary.289 117. In summary, the Board finds the IPEC BPTIP exceeds the recommendations in NUREG-1801, Rev. 1 AMP XI.M34 and meets the key elements or objectives of NUREG-1801, Rev. 2, AMP XI.M41.290 Given that NUREG-1801, Rev. 2, AMP XI.M41 was issued after Entergy submitted its LRA, it does not apply directly to the IPEC LRA.291 However, the NRC 284 Id.

285 Id.

286 NL-12-174, Attach. 1 at 21 (ENT000597).

287 See Entergy Testimony at 54 (A75) (ENTR30373).

288 See id at 81-82 (A100-01); Dec. 10, 2012 Tr. at 3541:11-16 (Holston) (noting that the UFSAR supplement becomes part of a plants current licensing basis).

289 Dec. 10, 2012 Tr. at 3360:4-14, 3361:8-18 (Holston); see also id. at 3541:1-4 (Holston) (stating that the UFSAR supplement is incorporated into the UFSAR and is the regulatory hook for key program elements).

290 In this regard, the Board concludes that the IPEC BPTIP does, in fact, follow the dictates of Section XI.M41 of NUREG-1801, Rev. 2, as issued in December 2010. New York Rebuttal Testimony at 8:15-18, 11:25-12:2 (NYS000399); New York Revised Statement of Position at 18 (NYS000398).

291 NRC Staff Testimony at 12 n.3 (A8) (NRCR20016).

Staff has evaluated Entergys BPTIP against what Mr. Holston and Ms. Green properly described as the key elements of AMP XI.M41 (e.g., number of inspections, soil sampling, and use of plant specific operating experience), and concluded that Entergys revised BPTIP is adequate to ensure that buried piping and tanks will continue to perform their intended functions.292 The Board agrees that the Entergys action in increasing the number of planned inspections, among other things, is consistent with the Staffs position in NUREG-1801, Revision 2 and Final LR-ISG-2011-03 (NRC000162).293 Finally, the Board finds that the BPTIP has been appropriately documented in the IPEC LRA, as reflected in LRA Sections A.2.1.5, A.3.1.5, B.1.6, and Entergys List of Regulatory Commitments.294 D. Relationship of the IPEC BPTIP to Entergys 10 C.F.R. Part 50 Underground Piping Program and Entergys Associated Fleet and Plant-Specific Procedures 118. Entergy witnesses (Azevedo, Cox, Ivy and Lee) testified that Entergys application of the BPTIP is closely linked to IPECs current, 10 C.F.R. Part 50-based Underground Piping and Tanks Inspection and Monitoring Program, or UPTIMP, and the nuclear industrys Underground Piping and Tanks Integrity Initiative.295 Mr. Cox and Mr. Ivy stated that Entergy developed the UPTIMP to implement the industry initiative.296 119. The Underground Piping and Tanks Initiative seeks to provide reasonable assurance of the structural integrity of underground piping and tanks at nuclear power plants.297 The initiative seeks to accomplish this objective by assessing and managing the condition of 292 Id.

293 Id. at 36 (A29).

294 The current versions of these LRA sections are contained in Attachments 1 and 2 to Entergy letter NL-12-174 (ENT000597).

295 See Entergy Testimony at 58-59 (A78-79), 73-74 (A90) (ENTR30373); Dec. 11, 2012 Tr. at 3602:16-24 (Cox).

296 Entergy Testimony at 58 (A78) (ENTR30373).

297 Id. at 54-55 (A76).

piping and tanks within the initiatives scope, sharing industry operating experience, and fostering technology development to improve available techniques for inspecting and analyzing underground piping and tanks.298 Broadly speaking, the Underground Piping and Tanks Integrity Initiative includes the following key program attributes: (1) Procedure and Oversight, (2) Risk Ranking/Prioritization, (3) Inspection Plan/Condition Assessment Plan, (4) Plan Implementation, and (5) Asset Management Plan.299 120. The NEI Buried Piping Integrity Working Group and Task Force has developed a guidance document, NEI 09-14, to explain the intent of the initiative and facilitate its implementation. The current version of that document, NEI 09-14, Rev. 2, was issued in November 2012.300 Appendix C to NEI 09-14, Rev. 2 includes the industrys Guidance for Inspection and Condition Assessment of Buried and Underground Piping and Tanks.301 According to Entergys witnesses, Appendix C provides a technically sound, consistent industry approach to developing inspection plans that establish reasonable assurance of buried and underground piping integrity.302 It addresses topics such as susceptibility analysis, direct and indirect inspection methods, post-examination assessment, and fitness-for-service evaluations.303 121. Entergy has developed a program document, fleet procedures, and an IPEC-specific inspection plan to implement the UPTIMP and meet the industry guidelines in NEI 09-298 Id.

299 Id. at 55 (A76).

300 NEI 09-14, Rev. 2 (ENT000601). Additional detailed guidance is provided in EPRI 1016456, Recommendations for an Effective Program to Control the Degradation of Buried Pipe (Dec. 2008) (EPRI 1016456) (NYS000167). EPRI 1016456 is a technical basis document created to assist the development of licensee buried piping programs and is specifically referenced in NEI 09-14 as implementation guidance.

301 NEI 09-14, Rev. 2, app. C (ENT000601).

302 Entergy Testimony at 56-57 (A76) (ENTR30373).

303 Id.

14 at IPEC.304 As stated in Entergys testimony, there are four principal documents being used to implement the UPTIMP.305 CEP-UPT-0100, Rev. 1, Underground Piping and Tanks Inspection and Monitoring Program (Nov. 30, 2012) (CEP-UPT-0100) (ENT000598) is an Entergy corporate program document that lays out the key elements of the UPTIMP (e.g.,

component identification and sample selection methodology, inspection methodologies, evaluation of inspection data, repair and mitigation strategies).306 122. CEP-UPT-0100, Rev. 1 is closely linked to EN-DC-343, Underground Piping and Tanks Inspection and Monitoring Program, Rev. 6 (Nov. 30, 2012) (EN-DC-343)

(ENT000599), and states that the latter document contains the program controls.307 More specifically, EN-DC-343 provides the requirements for each site to develop its own site-specific UPTIMP.308 EN-DC-343 describes its relationship to CEP-UPT-0100 as follows:

The details of the risk ranking criteria, reasonable assurance guidance, recommendations for inspection, monitoring, and mitigation portion of this Program are contained in Program Section CEP-UPT-0100. This procedure and CEP-UPT-0100 contain the required elements to provide guidance and recommendations for a programmatic approach to help Program Owners prioritize inspections of underground segments, evaluate the inspection results, make fitness for service decisions, select a repair technique where required, and take preventive measures to reduce the likelihood and consequence of failures.309 123. SEP-UIP-IPEC, Rev. 0, Underground Components Inspection Plan (Apr. 29, 2011) (SEP-UIP-IPEC) (NYS000174) documents the IPEC site-specific inspection plan for 304 See id. at 73 (A90) (ENTR30373); Dec. 10, 2012 Tr. at 3481:21-3482:18 (Cox, Ivy); id. at 3483:9-25 (Ivy)

(So the program does currently reflect all the requirements of the initiative.).

305 Entergy Testimony at 58-59 (A78), 70-71 (A88) (ENTR30373).

306 Id. at 58 (A78); CEP-UPT-0100, Rev. 1 (ENT000598).

307 CEP-UPT-0100, Rev. 1 at 5 (ENT000598).

308 EN-DC-343, Rev. 6 at 3 (ENT000599).

309 Id.

underground and buried piping and tanks.310 During the hearing, Mr. Lee clarified that CEP-UPT-0100 provides the methodology for performing the risk ranking, and SEP-UIP-IPEC contains the risk ranking results; i.e., the established inspection priorities (high/medium/low) and associated inspection intervals.311 Section G of SEP-UIP-IPEC summarizes the IPEC risk ranking process.312 Section H of SEP-UIP-IPEC describes applicable inspection and examination methods for buried pipes and tanks, which include in-line pipeline examinations using instrumented vehicles (called pigs), guided wave indirect inspections, local pipe direct examination (NDE), and direct visual inspections of excavated piping.313 Section H also describes the pipe line grouping process, whereby pipes are grouped based on attributes such as pipe material, coating type, soil/backfill, age, operating parameters, size, process fluid, and cathodic protection.314 124. The Appendices to SEP-UIP-IPEC provide additional details. Appendix A, for example, contains detailed piping inspection information for piping within the scope of the UPTIMP (and hence the license renewal BPTIP). That information includes, among other things, risk ranking information.315 For each unit, the piping is listed in order of inspection priority, from high to low.316 Appendix G contains an integrated inspection schedule that 310 Entergy Testimony at 70-71 (A88) (ENTR30373); SEP-UIP-IPEC, Rev. 0, Underground Components Inspection Plan at 5 (Apr. 29, 2011) (SEP-UIP-IPEC, Rev. 0) (NYS000174); see also Dec. 10, 2012 Tr. at 3413:11-15 (Holston) (agreeing that SEP-UIP-IPEC is a site-specific procedure that lists the buried piping segments, their risk ranking, and the schedule for planned inspections).

311 Dec. 10, 2012 Tr. at 3457:20-3458:6 (Lee).

312 SEP-UIP-IPEC, Rev. 0 at 9-10 (NYS000174).

313 Id. at 10-14.

314 Id. at 11; see also Dec. 11, 2012 Tr. at 3622:18-25 (Lee) (discussing pipe grouping process). The grouping of pipes with similar attributes allows the results of the inspection of one pipe to be extrapolated to the others in the group, thereby optimizing inspection scope. SEP-UIP-IPEC, Rev. 0 at 11 (NYS000174).

315 SEP-UIP-IPEC, Rev. 0 at 19-51 (NYS000174).

316 Entergy Testimony at 71 (A88) (ENTR30373).

identifies the specific excavated direct visual inspections to be performed through the third quarter of 2013.317 Finally, Appendix H contains program drawings of the piping systems and locations to be inspected, and identifies the exact inspection locations.318 125. EN-EP-S-002-MULTI, Rev. 1 (ENT000600) is an Entergy engineering standard that specifies requirements for general visual inspections of buried and underground piping and tanks.319 EN-EP-S-002-MULTI states that it satisfies the requirements of EN-DC-343 and CEP-UPT-0100 and applies to personnel inspecting components per those procedures.320 Among other things, it specifies coating personnel qualification requirements and provides inspection guidelines applicable to pipe coatings, base metal surfaces, and backfill makeup.321 E. Enforceability of Entergy Procedures 126. During the hearing, the Board inquired about the relationship between Entergys license renewal BPTIP and UPTIMP, including the aforementioned Entergy procedures.322 With regard to the scope of the two programs, Mr. Cox explained that the BPTIP is a subset of the UPTIMP, which includes all buried and underground piping on site.323 The BPTIP has a more 317 SEP-UIP-IPEC, Rev. 0 at 65 (NYS000174). Mr. Lee testified that SEP-UIP-IPEC is intended to function as an active database because it will be updated periodically to capture the results of completed inspections and relevant operating experience. Dec. 11, 2012 Tr. at 3620:7-21 (Lee); see also id. at 3692:4-11 (Azevedo),

3865:4-11 (Lee) (stating that SEP-UIP-IPEC is a living document and an active record of our plans to excavate and inspect in the future, as well as completed excavations and inspections that is available onsite for the NRC to review).

318 SEP-UIP-IPEC, Rev. 0 at 66-69 (NYS000174).

319 Entergy Testimony at 87 (A107) (ENTR30373).

320 EN-EP-S-002-MULTI, Rev. 1 at 4 (ENT000600).

321 Id. at 10-12.

322 See, e.g., Dec. 10, 2012 Tr. at 3479:5-9 (Judge Wardwell).

323 Id. at 3479:10-25, 3482:4-9 (Cox); see also Entergy Testimony at 32 (A49), 59 (A79) (ENTR30373).

limited scope, and includes only that piping which performs one or more of the intended functions identified in 10 C.F.R. § 54.4(a)(1)-(3) and are within the scope of license renewal.324 127. Mr. Cox and Mr. Azevedo stated that the four Entergy procedures described above also apply to the IPEC BPTIP and are being used to administer that program.325 Mr.

Holston stated that corporate procedures are not binding on a licensee, for NRC regulatory purposes, unless they are NRC regulatory requirements or are incorporated in the license or the UFSAR.326 However, he subsequently clarified that the essential aspects of the program, including preventive measures to mitigate corrosion, trending of inspection results, quantity and frequency of inspections, quantity and frequency of soil sampling, and expansion of inspection scope should the soil be demonstrated to be corrosive, are all included in the Applicants UFSARs.327 Mr. Holston also noted that changes to procedures described in the UFSAR can only be made in accordance with the 10 C.F.R. § 50.59 process.328 128. Mr. Cox agreed with Mr. Holston that the essential aspects of NUREG-1801 and the BPTIP are included in the IP2 and IP3 UFSARs and, accordingly, are subject to the 10 324 Entergy Testimony at 59 (A79) (ENTR30373).

325 See id. at 69 (A88); Dec. 10, 2012 Tr. at 3420:23-25 (Cox) (stating that both the corporate procedures and the site-specific procedure apply to the program at Indian Point); id. at 3465:9-13 (Azevedo) (confirming for the Board that EN-DC-343 applies in its entirety to IPEC); id. at 3480:7-9 (Cox) ([T]he procedures that are implemented, that also implement the UPTIMP are implementing those requirements that are described in the BPTIP.).

326 NRC Staff Testimony at 57 (A47) (NRCR20016).

327 Id.

328 Dec. 10, 2012 Tr. at 3467:25-3468:2 (Holston) (These provisions [in EN-DC-343, CEP-UPT-0100, and SEP-UIP-IPEC] would be enforceable in relation to the UFSAR supplement.); id. at 3468:16-17 (Holston) (That is true with every provision that links to the UFSAR supplement.); id. at 3473:8-11 (If there are links if its a level of detail in the UFSAR, its almost a foregone conclusion that you'll have to perform a 50.59 evaluation.).

C.F.R. § 50.59 process.329 However, he further asserted that actions required by Entergys corporate and plant-specific procedures can be enforced by the NRC.330 He explained that Entergy uses those procedures to meet the requirements of the BPTIP and related commitments, and that the NRC can issue a violation to Entergy for failing to follow a procedure, or for changing the procedure without appropriately evaluating the impact on license renewal commitments.331 Mr. Cox noted that Entergy incorporates references to its specific license renewal commitments in its procedures to ensure that any procedure changes are appropriately evaluated.332 129. Mr. Cox and Mr. Holston explained that Entergy must conduct a rigorous internal review to determine whether any change to a procedure would conflict with a commitment in the IPEC UFSAR Supplement or other licensing basis document, and that the results of that review are subject to NRC oversight.333 As described in Entergys corporate Process Applicability Determination (PAD) procedure,334 when a procedure change is proposed, an engineer must complete a PAD Form to determine: (1) whether the proposed change will affect, or has the potential to affect, any licensing basis documents and processes; (2) the appropriate regulation to 329 Id. at 3539:10-16 (Cox) ([T]he SAR supplement says that the program will be implemented consistent with the corresponding program described in NUREG-1801, Section XI-M34. . . . Weve included everything thats in the GALL report as a key element in the SAR supplement through this reference.).

330 Id. at 3470:4-7 (Cox) (So to the extent that these are site procedures, they have to be followed by Entergy.

They are enforceable in the sense that if we dont do what the procedure says, we are subject to a violation.).

331 Id. at 3356 3355:20-3356:5 (Cox).

332 Id. at 3356:6-9 (Mr. Cox).

333 See id. at 3399:13-21 (Cox) (There may be a change in procedure that may not affect the description of the program in the SAR but we still have to go through that screening process to make sure that is the case.); id.

at 3469:23-3470:25, 3471:17-21 (Cox); id. at 3472:16-24 (Holston); see also Dec. 11, 2012 Tr. at 3649:1-20 (Green); id. at 3662:11-23 (Cox).

334 At the hearing, the witnesses often referred to this procedure as the 10 C.F.R. § 50.59 screening procedure.

See, e.g., Dec. 10, 2012 Tr. at 3403:10-14 (Holston) (stating that every administrative procedure goes through a 50.59 screen to whether a 50.59 evaluation is necessary); id. at 3471:17-3472:4 (Cox); Dec. 11, 2012 Tr. at 3655:13-16 (Azevedo) (stating that all procedure changes go through the 50.59 screen whether they are in the FSAR or not.).

be used to review the proposed change; and (3) whether the proposed change requires a full 10 C.F.R. § 50.59 evaluation.335 The PAD form itself is a seven-page document that requires the preparer to research and review applicable licensing basis documents; identify any regulations, licensing basis documents, and procedures that may be implicated or impacted by the proposed change; determine whether the proposed change requires review under 10 C.F.R. § 50.59 or other regulation; and, if a full Section 50.59 review is not required, to provide a narrative explanation of the basis for that conclusion.336 130. For those proposed procedure changes that do require a Section 50.59 evaluation, Entergys 10 CFR 50.59 Evaluations procedure establishes the methods for preparing, reviewing, approving, and documenting such evaluations.337 Evaluations are documented on a 50.59 Evaluation Form.338 Similar to the PAD process, upon completion of the 50.59 Evaluation Form, a second individual performs a concurrence review for the proposed change.339 If the reviewer concurs with the results, then the evaluation form is reviewed by the IPEC On-Site Safety Review Committee for final approval.340 131. In summary, the Board finds that application of the BPTIP described in Entergys LRA will be governed by the same detailed fleet and plant-specific procedures that govern Entergys Part 50-based program for buried and underground piping, the UPTIMP. Those 335 See EN-LI-100, Process Applicability Determination, Rev. 12, at 11 (Nov. 6, 2012) (EN-LI-100, Rev. 12)

(ENT000602); see also Dec. 11, 2012 Tr. at 3662:25-3663:17 (Azevedo) (describing the PAD process).

336 See EN-LI-100, Rev. 12 at 19-25. Upon completion of the PAD Form, a second individual (who is also trained and qualified to perform PADs) performs a concurrence review for the proposed change. If the reviewer concurs with the results, the PAD Form is then reviewed by a third individual, generally a department-level manager, for final approval. Id. at 10.

337 See EN-LI-101, Rev. 9, 10 CFR 50.59 Evaluations (ENT000603).

338 See id. at 15-17.

339 See id. at 9.

340 Id. at 7.

procedures provide substantial additional details related to the BPTIP.341 Contrary to New Yorks claim, Entergy cannot modify its procedures at will without assessing the impact of any changes on its license renewal BPTIP and related commitments.342 Entergy must evaluate proposed procedure modifications in accordance with its PAD procedure and, if applicable, its 10 CFR 50.59 Evaluations procedure to determine whether the procedure change would conflict with a commitment in the IPEC UFSAR Supplement or other licensing basis document.343 F. Technical Description of the IPEC BPTIP

1. Entergy has fully identified the buried and underground piping that is within the scope of license renewal and subject to the BPTIP, including piping that contains or may contain radioactive fluids.

132. In their pre-filed testimony, Entergys and the NRC Staffs witnesses identified the specific portions of IP2 and IP3 buried piping that are subject to AMR and included within the scope of the IPEC BPTIP.344 That buried piping includes portions of the following IPEC systems:

• Safety injection (IP3 only): Approximately 700 feet of stainless steel piping running from the refueling water storage tank (RWST) to the auxiliary building that 341 For example, Entergys procedures provide additional details regarding risk ranking methods; soil analysis; cathodic protection (maintenance, monitoring and surveys); excavation, shoring, and backfilling; pipe and tank inspection techniques; implementation of inspections; scope expansion; interface to fitness-for-service assessment and trending; storage and coating and base metal; inspection criteria; fitness-for-service calculation methods and margins; determination of degradation rates and re-inspection interval; and repairs (for coatings, linings, piping, tanks, tunnels, trenches, and vaults). See Entergy Testimony at 58-59 (A78) (ENTR30373).

342 Dec. 10, 2012 Tr. at 3469:23-3470:25 (Cox).

343 Dec. 11, 2012 Tr. at 3669:12-17 (Holston) (agreeing with Judge Wardwell that it is incumbent upon Entergy to be performing [its] aging management and according to those procedures in order to maintain their consistency with GALL to provide the linkage thats needed).

344 Entergy Testimony at A46 (ENTR30373); Dec. 10, 2012 Tr. at 3308:23-3309:4 (Holston) (identifying buried piping systems within the scope of the IPEC BPTIP). As Mr. Holston noted, the specific in-scope buried piping systems are listed in the LRA Section B.1.6. Id. at 3372:16-20 (Holston). In addition, the LRA AMR Tables, which the Staff reviews, list of all of the components in the plant that are being managed for aging, and it lists them by material, environment, aging effect, and program. Id. at 3373:19-3374:5 (Holston).

supplies borated water to the suction of the safety injection and containment spray pumps.345

• Service water: A total of approximately 3800 feet of IP2 and IP3 carbon steel piping that carries service water to and from safety-related cooling loads in two separate parallel trains.346

• Fire protection: Approximately 5000 feet of IP2 and IP3 ductile iron or carbon steel piping that runs from fire water pumps through the fire protection loop that circles the main plant buildings. (The loop design and associated sectional isolation valves allow isolation of a leak in any segment of piping without disabling the remainder of the fire protection water system.)347

• Fuel oil: Approximately 160 feet of carbon steel piping that carries fuel oil from fuel oil storage tanks to associated diesel engines. Buried piping and tanks provide fuel oil for EDGs, as well as, the Appendix R diesel generator (IP3 only) and security diesel generator (IP2 only).348

• Security generator (IP3 only): Approximately 50 feet of carbon steel piping that provides the propane fuel to operate the IP3 security generator.349

• City water: Greater than 4000 feet of IP2 and IP3 carbon steel and gray cast iron piping that provides a backup source of water for auxiliary feedwater (AFW) and fire protection systems.350

• Plant drains: Greater than 1000 feet of IP2 and IP3 carbon steel piping that provides a drainage path from floor drains in the lower elevations of certain plant structures to waste holdup tanks.351

• Auxiliary feedwater: Approximately 1200 feet of carbon steel piping that serves as the suction line and recirculation line between the AFW pumps and the condensate storage tanks (CSTs) for each unit. About 1000 feet of this piping is for IP2, with the remainder of the piping serving IP3.352 345 Entergy Testimony at 27 (A46) (ENTR30373) (citing NL-09-106, Attach. 1 at 1 (NYS000203)).

346 Id.

347 Id.

348 Id. at 28 (A46) (citing NL-09-106, Attach. 1 at 2 (NYS000203)).

349 Id.

350 Id.

351 Id.

352 Id.

• Containment isolation support (IP2 only): Approximately 150 feet of carbon steel piping that provides pressurized air to support containment integrity for IP2.353

• Circulating Water (IP2 only): Approximately 1300 feet of carbon steel piping that supplies cooling water from the Hudson River to the IP2 condenser to condense steam exiting the low-pressure and main boiler feed pump turbines.354

• River Water (IP1 only): Approximately 460 feet of carbon steel piping from the pump discharge to the intertie to the IP2 service water system.355 Dr. Duquette did not argue that Entergy failed to identify any particular buried piping systems or segments as within the scope of the BPTIP.

133. More detailed descriptions of aforementioned systems and their intended functions are provided in Entergys testimony and the LRA sections cited therein.356 Additionally, in accordance with Entergy fleet procedure EN-DC-343,357 Entergy has developed detailed drawings of in-scope buried piping systems that show the locations of buried pipes at IPEC, including their location relative to other buried pipes and aboveground structures.358 The 353 See id.; NL-09-106, Attach. 1 at 1 (NYS000203).

354 Entergy Testimony at 28 (A46) (ENTR30373); LRA at 2.3-341 (ENT00015A); NL-09-079, Attach. 1 at 22 tbl.

3.4.2-5-3-IP2 (June 12, 2009) (ENT000403).

355 See Entergy Testimony at 31-32 (A48) (ENTR30373); NL-12-032, Letter from F. Dacimo, Entergy to NRC, Correction to Previous Response Regarding Unit 1 Buried Piping at 1-2 (Jan. 30, 2012) (ENT000381); LRA River Water System Unit 1 (Jan. 9, 2012 (ENT000422); see also Dec. 10, 2012 Tr. at 3491:18-3492:13 (Cox)

(explaining the addition of the IP1 river water segment to buried piping covered by the BPTIP); Dec. 11, 2012 Tr. at 3870:1-3 (Biagiotti) (stating that there are about 18,300 feet of pipe at IPEC); id. at 3871:1-2 (Holston)

(stating that there are about 17,360 feet of pipe absent river water).

356 See Entergy Testimony at 27-30 (A46) (ENTR30373).

357 EN-DC-343, Rev. 6 at 13 (ENT000599).

358 See Entergy Testimony at 66-67 (A86) (ENTR30373); Dec. 11, 2012 Tr. at 3705:6-13, 3705:16-3706:10 (Biagiotti). As Mr. Holston noted, under the CLB, Entergy is required to maintain plant drawings, to document any adverse as-found conditions and to update its drawings to reflect such conditions, pursuant to 10 C.F.R. Part 50, Appendix B, Criterion V (Instructions, Procedures, and Drawings). This requirement will continue to apply during the PEO, such that there is no need to duplicate this requirement in the LRA or AMP.

NRC Staff Testimony at 57 (A48) (NRCR20016); see also Dec. 10, 2012 Tr. at 3419:23-3420:3 (Cox) (stating that as-built drawings showing buried piping are maintained onsite).

locations of this in-scope piping are shown in Figure 1 of Entergys testimony and in Exhibits ENT000402 and ENT000409 through ENT000422.359 134. In October 2012, Entergy clarified that approximately 270 feet of below-grade piping meets the definition of underground piping in Section XI.M41 of NUREG-1801, Rev.

2; i.e., piping that is below grade and contained within a tunnel or vault, such that the piping is in contact with air and access for inspection is restricted.360 Specifically, Entergy identified portions of the service water, city water, and fuel oil systems that are located in vaults that require more than unlocking a hatch or cover for access.361 This piping is now considered underground piping as defined in NUREG-1801, Rev. 2 (NYS000147A-D) and Final LR-ISG-2011-03 (NRC000162).362 This in-scope piping previously was treated as accessible piping (as opposed to restricted-access piping) subject to aging management under the IPEC External Surfaces Monitoring Program.363 135. Of the systems within the scope of license renewal identified above, only the IP3 safety injection system contains radioactive fluids during normal operations, because it contains 359 Entergy Testimony at 30 fig. 1 (A46) (ENTR30373). During the hearing, Mr. Biagiotti stated that based on SIs digitized maps of IPEC buried piping, there is approximately 77,000 linear feet of buried piping at the IPEC site, of which approximately 18,300 feet is within the scope of license renewal. Dec. 11, 2012 Tr. at 3784:10-13, 3870:1-3 (Biagiotti).

360 The term restricted is not explicitly defined in NRC license renewal guidance documents. On October 11, 2012, Entergy held a conference call with the NRC Staff to clarify the definition of restricted as used in NUREG-1801, Rev. 2 and the Final ISG. See Summary of Telephone Conference Call Held on October 11, 2012 Between the U.S. Nuclear Regulatory Commission and Entergy Nuclear Operations, Inc., Concerning the Indian Point Nuclear Generating Unit Nos. 2 and 3, License Renewal Application (Oct. 31, 2012)

(ENT000595). During the call, the Staff clarified that it intended restricted to refer to piping that is located in vaults for which access requires more than simply opening a locked access cover. See Entergy Testimony at 29 (A46) (ENTR30373).

361 See NL-12-149 at 1-2 (ENT000596).

362 Id. at 1.

363 See Entergy Testimony at 29 (A46) (ENTR30373).

borated water with radioactive constituents from the RWST.364 Safety injection system buried components are made of stainless steel, which has low susceptibility to corrosion.365 136. Buried piping in the AFW, service water, and floor drain systems for IP2 and IP3 has the potential to contain radioactivity, but generally is not expected to contain radioactive fluids under normal operations.366 The IP1 river water piping within the scope of the BPTIP does not have the potential to contain radioactive fluids.367 Thus, as shown in Figures 1 and 2 of Entergys testimony, the piping at issue in NYS-5piping that contains or may contain radioactive fluidsis a small subset of the piping managed under the BPTIP.368 137. In summary, the record shows, and the Board is satisfied, that Entergy has identified: (1) those IP1, IP2, and IP3 systems containing buried piping components; (2) those buried components which support systems performing license renewal intended functions; and (3) those systems containing, or potentially containing, radioactive fluids.369 During the hearing, Dr. Duquette agreed that Entergy has performed a systematic and detailed inventory of IPEC buried piping, and confirmed that he has no reason to doubt the quality of that inventory.370 364 See id. at 32-34 (A50); LRA at 2.3-55 to 2.3-56 (ENT00015A); NRC Staff Testimony at 18 (A14)

(NRCR20016); Dec. 11, 2012 Tr. at 3697:6-11 (Cox).

365 Entergy Testimony at 32 (A50) (ENTR30373).

366 Id. at 32-33 (A50); NRC Staff Testimony at 18-19 (A114) (NRCR20016); Dec. 11, 2012 Tr. at 3697:12-3698:9 (Cox).

367 Entergy Testimony at 33 (A50) (ENTR30373); NRC Staff Testimony at 19-20 (NRCR20016).

368 Entergy Testimony at 30 (A46), 34 (A50) (ENTR30373). As discussed in Answers 47 and 52 of Entergys Testimony (ENTR30373), although there are a number of buried tanks that are within the scope of the BPTIP, those tanks are used only to store hydrocarbon fuels (fuel oil, diesel fuel, propane) and are not connected to systems that contain radioactive materials or fluids. Thus, they are not within the scope of NYS-5.

369 Ms. Green testified that [t]he staff is reasonably confident that theyve identified all the buried piping at Indian Point, for Indian Point Unit 1, 2 and 3, that should be within the scope of license renewal and is subject to [AMR]. Dec. 10, 2012 Tr. at 3489:18-22 (Green). Mr. Azevedo also testified that Entergy is confident that [it has] identified all the piping thats in the scope of license renewal. Id. at 3490:13-21 (Azevedo).

370 Dec. 11, 2012 Tr. at 3707:1-9 (Duquette).

2. The BPTIP manages loss of material due to external corrosion of buried and underground piping to provide reasonable assurance that the associated systems can perform their license renewal intended safety functions.

138. Entergys BPTIP is intended to manage material loss due to external corrosion of buried and underground piping to provide reasonable assurance that the associated systems can perform their license renewal intended functions.371 This fact is not in dispute. However, the parties expressed differing views on the meaning of intended function under 10 C.F.R. Part 54.372 139. As Mr. Holston explained, 10 C.F.R. § 54.4(a) describes the scope of SSCs that are required to be addressed in the LRA (see also Section III.A, supra).373 Further, 10 C.F.R.

§ 54.4(b) states, The intended functions that these [SSCs] must be shown to fulfill in § 54.21 are those functions that are the bases for including them within the scope of license renewal as specified in paragraphs (a)(1) - (3) of this section. Thus, only SSCs performing the functions that are described in 10 C.F.R. § 54.4(a) are within the scope of license renewal.

140. LRA Section 2, which describes Entergys scoping and screening, indicates that the function of these systems is to provide pressure boundary integrity such that adequate flow and pressure are maintained.374 Mr. Cox also testified that the BPTIP is intended to provide reasonable assurance that external corrosion of in-scope buried piping will not preclude the 371 LRA, app. B at B-27 (ENT00015B); NL-09-106, Attach. 1 at 5 (NYS000203).

372 Compare Dec. 10, 2012 Tr. at 3567:3-7 (Duquette) (stating that a pipes intended function is to maintain a pressure boundary and retain its fluid), with Dec. 10, 2012 Tr. at 3567:22-24 (Holston) (Im not aware of anything, anywhere that has the non-release of radioactive material being an intended function of a piping system for aging management purposes).

373 NRC Staff Testimony at 14-15 (A11), 25 (A20) (NRCR20016).

374 LRA at 2.1-1, 2.1-7 (ENT00015A).

ability of that piping to perform its intended function (maintaining pressure boundary) during extended operations. 375 141. LRA Table 2.0-1 describes this intended function as, Provide pressure boundary integrity such that adequate flow and pressure can be delivered. This function includes maintaining structural integrity and preventing leakage or spray for 54.4(a)(2).376 This definition of pressure boundary is consistent with the definition in NUREG-1800, Table 2.1-4(b),

Typical Passive Component-Intended Functions, and 10 C.F.R. § 54.4(a)(2), which states that in-scope SSCs include all nonsafety-related SSCs whose failure could prevent satisfactory accomplishment of any of the functions identified in 10 C.F.R. § 54.4 (a)(1)(i), (ii), or (iii).377 142. Dr. Duquette disagreed that the Part 54 intended safety function of buried piping is solely to maintain pressure boundary integrity.378 According to Dr. Duquette, The second, and perhaps more important function for piping systems such as those at IPEC that are not under high pressure, is to contain the fluid in the system.379 He further stated that [i]f the piping cannot perform that function it has, de facto, failed.380 143. The Board recognizes the importance of limiting radiological releases to the environment, but concurs with Mr. Holston and Mr. Cox that the intended function of the in-scope buried pipingas defined in 10 C.F.R. § 54.4is to maintain a pressure boundary; i.e.,

375 Entergy Testimony at 76 (A94) (ENTR30373).

376 LRA at 2.0-3 (ENT00015A).

377 NUREG-1800 at 2.1-17 (NYS000195); 10 C.F.R. § 54.4(a)(2) (emphasis added).

378 Dec. 10, 2012 Tr. at 3567:3-7 (Duquette).

379 New York Rebuttal Testimony at 18:5-7 (NYSR20399).

380 Id. at 18:7-8; see also Dec. 10, 2012 Tr. at 3554:6-9 (Duquette) (In my opinion, a piping system is of course, its supposed to contain a fluid, whether it be a gas or a liquid fluid, and if it cant contain that fluid, then its at failure.); id. at 3555:20-22 (Duquette) (If it begins to lose its fluid, its lost its function as a fluid-containing device.); id. at 3560:7-9 (Duquette) (If you lose fluid from the pipe at any location other than the exit from the pipe, I believe that the pipe has failed its function.).

deliver flow between two points at an acceptable flow rate and pressure. It is not to act as a fluid-containing device, as Dr. Duquette claimed.381 Therefore, as Entergys witnesses stated, prevention or remediation of inadvertent leaks and groundwater protection, while important, are not intended functions identified in 10 C.F.R. § 54.4.382 Mr. Coxs testimony is consistent with the Commissions holding in Pilgrim that actions related to the timely detection and correction of inadvertent leaks to assure compliance with NRC public dose limits383 is an ongoing operational issue involving existing facilities regardless of whether those facilities are seeking or will seek license renewal.384 144. In view of the above, the Board finds that the intended safety function of in-scope buried components managed under the BPTIP is to maintain a pressure boundary, not to contain fluids or prevent inadvertent leaks as suggested by Dr. Duquette. The Board also rejects the notion put forth by New York that a leak from a buried pipe constitutes a de facto failure of that pipe for Part 54 aging management purposes, especially if that leak has no effect on the pipes ability to perform its intended safety function. Again, these findings are consistent 381 Dec. 10, 2012 Tr. at 3555:20-22, 3558:11-12 (Duquette).

382 Entergy Testimony at 77 (A94) (ENTR30373); see also Dec. 10, 2012 Tr. at 3570:24-3571:11 (Holston) (The only functions that are subject to Part 54 are those that are in scope. And when you review the in-scope criteria, leakage is not there. . . . I have not run across a single application yet where an applicant has had to state that one of the license renewal intended functions is to prevent leakage.).

383 At hearing, Mr. Cox clarified that the NRC dose limits in 10 C.F.R. Part 20 and 10 C.F.R. Part 50 (Appendix I) are different from the offsite exposure limits referred to in 10 C.F.R. § 54.4(a)(1)(iii) (i.e., those specified in 10 C.F.R. §§ 50.34(a)(1), 50.67(b)(2), 100.11). Specifically, insofar as Section 54.4 references offsite exposure limits, it focuses on accident mitigation and the limits that are applicable during an accident causing reactor core damage, which would involve radiation levels far in excess of those possibly caused by a buried pipe leaking radioactive fluids. See Dec. 10, 2012 Tr. at 3579:3-3580:10 (Cox). Indeed, Sections 50.34(a)(1),

50.67(b)(2), 100.11 all refer to major accidents assumed to result in substantial meltdown of the core with subsequent release of appreciable quantities of fission products.

384 Pilgrim, CLI-10-14, 71 NRC at 461 (emphasis added). For reasons unrelated to Part 54s aging management requirements, Entergy has implemented a comprehensive radiological groundwater monitoring program at IPEC, consistent with the Industry Groundwater Protection Initiative (NEI 07-07),which monitors, investigates, and characterizes contamination of groundwater from licensed radioactive material at IPEC. See Entergy Testimony at 77 (A94) (ENTR30373); NEI 07-07, Industry Ground Water Protection Initiative (GPI) (Aug.

2007) (ENT000423).

with the Commissions observation in CLI-10-14 that key safety functions are the focus of the license renewal safety review under 10 C.F.R. Part 54not the adequacy of ongoing NRC or licensee actions to address leakage incidents.385

3. The BPTIP appropriately relies on both preventive actions (coatings) and condition monitoring (inspections) to ensure that in-scope buried piping will continue to perform its intended function during the license renewal term.

145. As described in the LRA, the BPTIP relies on both preventive actions and condition monitoring.386 The programs preventive actions include coatings and wrappings on buried piping.387 LRA Section B.1.6 states, [p]reventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings.388 146. Coatings provide the primary form of corrosion control for buried piping by preventing a susceptible material from coming in contact with a corrosive environment.389 Specifically, coatings form a long-lasting moisture and chemical-resistant barrier that is bonded to the outer surface of the pipe and thereby creates a barrier between the soil and the pipe.390 NACE SP0169-2007 indicates that the desirable characteristics of a buried piping protective coating system include: (1) serving as a moisture barrier; (2) good adhesion to the piping surfaces; (3) the ability to resist the development of holidays (i.e., voids or imperfections) over time; (4) resistance to corrosive soil conditions; (5) robustness to resist against damage during 385 Pilgrim, CLI-10-14, 71 NRC at 461.

386 Entergy Testimony at 46 (A63) (ENTR30373).

387 Id. at 46 (A64), 47-48 (A67).

388 LRA, at app. B at B-27 (ENT00015B).

389 Entergy Testimony at 42 (A60) (ENTR30373) (citing NACE SP0169-2007 (ENT000388); NACE Paper 10059 at 1-2 (ENT000389)).

390 Id. at 42 (A60) (ENTR30373).

storage, handling, installation and operation; and (6) resistance to disbondment due to mechanical stresses or cathodic impressed current.391 147. Protective coatings and wrappings were installed on IP2 and IP3 buried piping during construction of the units, in accordance with standard industrial practices, and they continue to be installed when replacement or repair activities are necessary (including during the PEO).392 Engineering specifications in place at the time of IP2 and IP3 construction contained procedures for installing and inspecting coatings applied by the piping manufacturer and for coatings applied in the field (e.g., at pipe joints).393 As noted above, the majority of IPEC buried piping within the scope of the BPTIP is carbon steel piping.394 Those systems containing or potentially containing radioactive material are made of stainless steel (IP3 safety injection system) or carbon steel (AFW, service water, and floor drain systems).395 148. The applicable site piping specifications required that all steel pipe and fittings be cleaned, coated, and wrapped with coal tar enamel and an asbestos fiber wrap in accordance with AWWA C-203-62, AWWA Standard for Coal-Tar Enamel Protective Coatings for Steel Water Pipe (Jan. 1962) (ENT000393).396 AWWA Standard C-203-62 required a coal tar coating covered with a fiber-based wrap saturated with coal tar.397 This is consistent with nuclear and industry standards for buried piping at the time of construction of IP2 and IP3.398 391 Id. at 47 (A66) (citing NACE SP0169-2007 at 6-7 (ENT000388)).

392 NRC Staff Testimony at 34-35 (A29) (NRCR20016).

393 Entergy Testimony at 48 (A68) (ENTR30373).

394 Id.

395 Id.

396 Id.

397 Id.

398 Id. at 51 (A70); Dec. 11, 2012 Tr. at 3638:13-16 (Cox).

149. Mr. Biagiotti and Mr. Cavallo testified that overall industry experience (including non-nuclear applications) demonstrates that coal tar coatings of the type specified for IPEC buried piping continue to adequately protect buried steel piping from corrosion even after having been in service for periods well beyond forty years.399 Coal tar enamel has the longest performance record of all pipeline coatings available today and ranks first in the following five essential post-installation measurements of successful performance: (1) resistance to cathodic disbondment; (2) resistance to water penetration; (3) in-use with a cathodic protection system; (4) low maintenance costs; and (5) resistance to physical changing/aging.400 The standards for this type of coating have existed for many decades with only minor changes (i.e., generally formulation changes due to environmental regulations governing use of volatile organic compounds).401 In this regard, Mr. Cavallo testified that the coal tar enamel coating system used on IPEC in-scope buried piping is a very, very durable, rugged, well-designed coating system that has performed well across many industries.402 150. The BPTIPs condition monitoring component includes extensive excavated direct visual inspections of buried piping that are used to confirm the condition of piping backfill, coatings, and external surfaces.403 The BPTIP inspection program assesses the integrity of the protective coatings to ensure that the exterior surfaces of buried piping are protected 399 See Entergy Testimony at 51-52 (A71) (ENTR30373); see also Dec. 11, 2012 Tr. at 3613:9-13, 3828:2-11 (Cavallo).

400 See Entergy Testimony at 51-52 (A71) (ENTR30373).

401 See id.; Dec. 11, 2012 Tr. at 3614:4-5 (Cavallo).

402 Dec. 11, 2012 Tr. at 3828:5-8 (Cavallo).

403 Entergy Testimony at 54 (A75) (ENTR30373); see also Dec. 11, 2012 Tr. at 3606:6-10 (Lee) (Our inspection program, the number of direct visual inspections of carbon steel coated pipe would provide us the ability to assess the condition of the as-found condition of the coating on the piping.); id. at 3834:2-6 (Holston) (stating that excavated direct visual inspections of buried piping include examination of the backfill quality).

against degradation.404 As long as the protective coatings remain intact, the buried piping will be isolated from potentially corrosive environments and protected from external degradation.405 151. As Mr. Holston explained, inspection locations are selected based on risk (i.e.,

potential for failure and consequence of failure).406 Inspection results are trended to identify portions of buried piping systems that might have history of corrosion problems and require evaluation for additional inspection, alternate coating, or replacement.407 If degradation of the coatings or base metal loss is identified, then further analysis and evaluation is required in accordance with 10 C.F.R. Part 50, Appendix B, potentially resulting in repair or replacement of the coating and piping or additional and more frequent inspections.408

4. The BPTIP provides sufficient details concerning planned inspections, acceptance criteria, and corrective actions.

152. Dr. Duquette claimed that Entergy has made inconsistent statements concerning the number and timing of buried piping inspections and the applicable acceptance criteria.409 He stated that Entergy offers no pipe classification, determination of corrosion risk, inspection priority or frequency list, or specific inspection techniques it will use.410 Dr. Duquette further asserted that Entergy has not specified the criteria governing decisions related to continued service, repair, or replacement of in-scope buried piping managed under the BPTIP.411 For the reasons stated below, the Board finds that Dr. Duquettes claims lack merit.

404 Entergy Testimony at 52 (A73) (ENTR30373).

405 Id. (citing NACE SP0169-2007 (ENT000388); NACE Paper 10059 at 2 (ENT000389)).

406 Dec. 10, 2012 Tr. at 3475:23-25 (Holston).

407 Dec. 11, 2012 Tr. at 3973:23-3974:1 (Holston).

408 Entergy Testimony at 87-88 (A107) (ENTR30373).

409 New York Direct Testimony at 24:19-20 (NYS000164).

410 Id. at 19:4-7.

411 See id. at 21:17-22.

a. Number and Timing Planned Inspections 153. As stated in Section II.B above, Entergy has committed to perform twenty (20) direct visual examinations for IP2 and fourteen (14) direct visual examinations for IP3 before the beginning of the PEO, and fourteen (14) direct visual examinations for IP2 and sixteen (16) direct visual examinations for IP3 during each ten-year interval of the PEO.412 Entergy has committed to perform its post-license renewal inspections over the course of each ten-year interval of the PEO (not once every ten years as suggested by Dr. Duquette), with each round of inspections building upon prior inspection results and other available operating experience.413 Thus, contrary to Dr. Duquettes claim, Entergy has not made inconsistent or ambiguous statements regarding the number and timing of its inspections.

b. Identification and Prioritization of Inspection Locations 154. Under the BPTIP, Entergy uses risk ranking of buried piping systems to inform its selection of inspection locations and to ensure that the scheduled inspections include high-priority areas (i.e., those areas that will have the highest consequence as a result of potential leakage and/or the highest likelihood of corrosion).414 The prioritization is determined by the use of a risk matrix that rates the likelihood of failure and the consequences of failure for a given SSC location.415 Those components ranked the highest receive the highest inspection higher 412 See Section II.B, supra. As stated previously, if the required soil testing discussed above identifies corrosive conditions, then Entergy has committed to increase the number of direct examinations as specified in the BPTIP.

413 See Entergy Testimony at 82-83 (A102) (ENTR30373); see also Dec. 10, 2012 Tr. at 3443:7-13 (Holston) (It is beyond my imagination to assume that all [inspections are] going to happen two days before the end of the ten-year period. No utility in its right mind will do 42 inspections in two weeks or in a month.).

414 Entergy Testimony at 72-73 (A89) (ENTR30373).

415 Id. at 70 (A88) (citing SEP-UIP-IPEC, Rev. 0 at 9 (NYS000174)).

priority.416 Section 5.2 (Component Identification and Sample Selection Methodology) of CEP-UPT-0100 describes this process in detail.417 155. Mr. Lee described the risk ranking process at the hearing.418 In brief, the process includes a determination of corrosion risk through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating.419 Buried pipe segments and tanks also are classified as having a high, medium or low impact of leakage based on the items safety class, the hazard posed by fluid contained in the piping, and the impact of leakage on reliable plant operation.420 Radiological SSCs are by definition considered high priority.421 Entergy has conducted the risk ranking process for IPEC, and that the resulting information has been entered into the BPWorks' 2.0 Risk Ranking Module database, which is an industry standard buried asset database that stores and integrates design, operation, inspection, and corrosion control information for use in the risk ranking and inspection prioritization processes.422 156. Dr. Duquette claimed that there is insufficient information concerning Entergys buried component classification, corrosion risk assessment, and inspection prioritization processes in the BPTIP.423 However, as Mr. Holston explained, the level of detail deemed necessary by Dr. Duquette is not required in an AMP to satisfy NRC regulatory requirements or 416 Id.

417 See CEP-UPT-0100, Rev. 1 at 10-16 (ENT000598); id. at 24-26 tbls. 9.2-9.4.

418 Dec. 10, 2012 Tr. at 3457:20-3460:23 (Lee).

419 Id. at 3459:7-19 (Lee); Dec. 11, 2012 Tr. at 3721:5-10 (Lee); CEP-UPT-0100, Rev. 1 at 25 tbl. 9-3 (ENT000598).

420 Dec. 10, 2012 Tr. at 3457:20-24 (Lee).

421 Id. at 3458:19-21 (Lee).

422 Entergy Testimony at 70 (A88) (ENTR30373).

423 New York Direct Testimony at 18:18-19:11 (NYS000164).

to conform to NUREG-1801 recommendations.424 Rather, such details are typically contained in a licensees inspection plans or AMP-implementing procedures.425 Mr. Cox, Mr. Ivy, Mr.

Azevedo, and Mr. Lee also confirmed that the details sought by Dr. Duquette are presented in Entergys procedures and the EPRI guidance on which those procedures are based.426 157. Mr. Holston further explained that an applicant is required to have such details available for Staff verification during on-site inspections conducted under NRC Inspection Procedure 71003, Post-Approval Site Inspection for License Renewal (Feb. 15, 2008)

(ENT000251).427 The IP 71003 process verifies that license conditions added as part of the renewed license, license renewal commitments, selected AMPs, and license renewal commitments revised after the renewed license was granted, are implemented in accordance with 10 C.F.R. Part 54.428 It also verifies that AMP descriptions contained in the UFSAR Supplements are consistent with the programs being implemented by the licensee.429 To that end, the NRC reviews program documents, instructions, and procedures that the licensee has committed to follow in implementing its AMPs.430 158. Mr. Holston testified that during the week of March 5-9, 2012, the NRC Staff conducted an onsite inspection under Temporary Instruction (TI) 2516/001431 to verify 424 NRC Staff Testimony at 45-47 (A36) (NRCR20016); see also Entergy Testimony at 17-18 (A34)

(ENTR30373).

425 NRC Staff Testimony at 47 (A36) (NRCR20016).

426 Entergy Testimony at 72-73 (A89) (ENTR30373).

427 Dec. 10, 2012 Tr. at 3356:13-3357:4 (Holston); see also id. at 3469:9-15 (Holston).

428 Id. at 3360:4-14, 3469:9-17 (Holston).

429 Id.

430 Id. at 3469:12-15 (Holston) (stating that the 71003 inspection includes confirming that the applicants commitments are incorporated into its procedures).

431 Recognizing that certain license renewal applicants initial operating terms may expire before those applicants receive renewed licenses, the NRC Staff issued TI 2516/001 (ENT000252), which allows NRC inspectors to assess progress in implementing license renewal AMPs and commitments during the pendency of the renewed Entergys progress in satisfying its license renewal commitments.432 During that inspection, in which Mr. Holston participated, the Staff confirmed that Entergys IPEC-specific program, which is modeled on its corporate program, CEP-UPT-0100, contains adequate details for assessing the risk of failure and corrosion for in-scope buried piping and tanks.433 The Staff also confirmed that Entergy used its corporate process to classify in-scope buried piping and tanks, as documented in site procedure SEP-UIP-IPEC (NYS000174).434

c. Inspection Methods and Acceptance Criteria 159. The BPTIP monitors buried piping coating integrity through the use of visual inspection techniques. Entergy has incorporated the inspection methods and acceptance criteria described in NUREG-1801 and industry guidance documents in its corporate procedures.

Specifically, to visually assess the condition of pipe coatings and pipe base metal surfaces for indications of degradation that may affect structural integrity, Entergy inspectors apply the criteria in Entergy Engineering Standard EN-EP-S-002-MULTI, Rev. 1.435 With respect to coatings, that procedure requires additional review of the condition and initiation of a condition report as required if there is any indication of coating degradation (e.g., delamination, mechanical damage, cracking, blistering, flaking, peeling, separation from pipe, embrittlement).436 license approval process. Given that the IP2 initial operating license expires in September 2013, NRC Region I inspectors completed an inspection at IP2 under TI 2516/001 during the week of March 5-9, 2012.

432 Dec. 11, 2012 Tr. at 3629:13-19, 3686:13-20, 3686:23-3687:13 (Holston) (discussing the Staffs TI 2516/001 inspection at IPEC, including Mr. Holstons review of procedures and buried piping inspection reports).

433 Dec. 10, 2012 Tr. at 3416:5-9 (Holston) (So Indian Point is right in the mainstream of level of detail and risk ranking.).

434 Id. at 3418:2-16 (Holston).

435 Entergy Testimony at 87 (A107) (ENTR30373) (citing EN-EP-S-002-MULTI, Rev. 1 (ENT000600)); see also Dec. 10, 2012 Tr. at 3484:22-3485:8, 3485:11-21 (Lee) (describing EN-EP-S-002-MULTI, Rev. 1 the engineering standard by which direct visual inspections of buried pipes and coatings are performed).

436 See EN-EP-S-002-MULTI, Rev. 1 at 11, 14 (ENT000600); Dec. 10, 2012 Tr. at 3485:3-21 (Lee).

160. With respect to the piping base metal, EN-EP-S-002-MULTI, Rev. 1 requires the initiation of a condition report if any of the following conditions are observed: cracking in the base metal; discoloration resulting from age, heat, or corrosion; discernible wear; pits, dents, or gouges in the base metal; excessive external corrosion; corrosion which results in discernible base metal loss; discernible bulges; arc strikes; or any other conditions causing discernible degradation of the base metal.437 For UT inspections, which are performed after an excavated pipes coating is removed to measure pipe wall thickness, the acceptance criterion is a wall thickness greater than 87.5% of the nominal wall thickness.438

d. Corrective Actions 161. Mr. Holston testified that, by committing to adhere to the IPEC corrective action program, procedures and administrative controls (including formal review and approval processes such as the PAD process discussed above), which were established under the current operating licenses in accordance with 10 C.F.R. Part 50, Appendix B, Entergys BPTIP satisfies GALL AMP XI.M34 and provides sufficient information to support a conclusion that the corrective action program is adequate.439 162. Corrective actions are accomplished by repair, replacement, or modification of the affected component in accordance with the design controls as described in 10 C.F.R. Part 50, Appendix B, Criterion III, which effectively provides for a comparison of the as-found piping to the plants design criteria (as documented in plant specifications, drawings, procedures).440 Under the current IP2 and IP3 operating licenses, Entergy is required to promptly identify and 437 EN-EP-S-002-MULTI, Rev. 1 at 10-11 (ENT000600).

438 CEP-UPT-0100, Rev. 1 at 17 (ENT000598).

439 NRC Staff Testimony at 54-55 (A45) (NRCR20016); Dec. 10, 2012 Tr. at 3399:10-3400:10 (Cox) (citing PAD or Section 50.59 screening process as an example of an administrative control).

440 NRC Staff Testimony at 54-55 (A45) (citing 10 C.F.R. Part 50, app. B, at Criterion III).

correct conditions adverse to quality.441 The identification of a condition adverse to quality is accomplished by comparing the as-found condition of the piping and coatings to the acceptance criteria, and to determine if the SSC is fit for duty until a subsequent inspection, or if the SSC must be immediately repaired or replaced.442 163. At IPEC, Entergy takes any necessary corrective actions in accordance with the requirements of 10 C.F.R. Part 50 and Entergy procedure EN-LI-102, Corrective Action Process, Rev. 17 (Dec. 8, 2011) (ENT000401).443 For example, as discussed in Section IV.G.1, infra, Entergy took numerous corrective actions in response to the February 2009 IP2 CST return line leak.

164. 10 C.F.R. Part 50, Appendix B, Criterion XVI (Corrective Actions), which requires that conditions adverse to quality (e.g., coating damage, external corrosion of buried piping) be corrected, continues to apply during the PEO.444 Accordingly, if the external surfaces of the piping, coatings, and backfill quality are found to not meet the standards imposed by the plants CLB, then there is reasonable assurance that they will be restored to meet existing license requirements.445 Mr. Holston stated that this consideration is factored into the Staffs evaluation of each AMP.446 441 Id. at 55 (A45).

442 Id.

443 See Entergy Testimony at 87-88 (A107) (ENTR30373); see also Dec. 10, 2012 Tr. at 3484:22-3485:21, 3486:6-11 (Mr. Lee); id. at 3551:23-3553:1 (Azevedo) (describing Entergys corrective action process, including the issuance of condition reports, screening of the condition reports to determine what level of evaluation is required, conduct of an apparent cause or root cause evaluation, establishment of corrective actions, review of the corrective actions by the Corrective Action Review Board, or CARB); Dec. 11, 2012 Tr. at 3693:1-3694:12 (Azevedo) (discussing Entergy corrective action process).

444 See NRC Staff Testimony at 54-56 (A45) (NRCR20016) (stating that NRC Staff has conducted routine inspections of the corrective action program under the existing licenses, and will continue to conduct routine inspections of the corrective action program during the period of extended operation).

445 Id. (stating that the combination of preventive actions, plans for extensive condition monitoring and inspection in conjunction with the use of risk-informed inspection locations, along with the Applicants G. Summary of Plant-Specific Operating Experience Relevant to the Condition of IPEC Buried Piping Coatings, Backfill, and Base Metal 165. In this portion of its decision, the Board summarizes relevant operating experience related to IPEC in-scope buried piping. Based upon its review of the record evidence, the Board finds that Entergys recent operating experience provides substantial insights into the condition of in-scope IPEC piping, including its protective coatings and surrounding backfill.447 This operating experience indicates that, contrary to New Yorks suggestion, buried piping coating degradation, poor backfill quality, or metal loss are not widespread or systemic issues at IPEC.448 166. Indeed, New York and Dr. Duquette focused almost exclusively on the most significant adverse IPEC operating experience, that being the leak in the IP2 CST return line that Entergy discovered in February 2009. For example, Dr. Duquette stated that the 2009 CST return line leak provides a cautionary tale about the condition of all of the buried piping at Indian Point, and that IPECs current proposed inspection program would not have been sufficient to have identified the possibility of a leak in this buried pipe.449 He also claimed that the backfill-related coating failure on the IP2 CST return line is irrefutable evidence that the specifications were not met 100% of the time at this site at the time of construction.450 Corrective Action program provides reasonable assurance that in-scope buried piping and tanks will meet their intended CLB functions during the period of extended operation).

446 Id.

447 Entergy Testimony at 53-54 (A75) (ENTR30373); see also Dec. 10, 2012 Tr. at 3452:1-12 (Azevedo) (So we have done a lot of testing, a lot of inspections.).

448 See Dec. 11, 2012 Tr. at 3948:6-8 (Azevedo) (But, in general, the soil has been good, the coating has been in generally good condition, and we found no significant issues.).

449 Duquette Report at 9-10 (NYS000165) (emphasis added).

450 New York Rebuttal Testimony at 4:22-22 (NYSR20399).

1. The 2009 Condensate Storage Tank (CST) Return Line Leak 167. Given New Yorks focus on the 2009 CST return line leak, we first discuss the circumstances surrounding that event and Entergys response to it, including the applicants resulting corrective actions. As described in Entergys testimony, on February 15, 2009, IPEC personnel observed water in a pipe sleeve in the floor of the AFW pump building.451 Entergy determined that the water observed in the pipe sleeve was due to a leak in the 8-inch diameter IP2 CST return line.452 After excavating a portion of the CST piping in the area of the identified leakage, Entergy identified a hole in the pipe where a small area of protective coating was missing.453 168. As part of Entergys evaluation, on February 17, 2009, vendor SI performed guided wave ultrasonic testing of the IP2 8-inch CST return line to screen several sections of the pipe for wall loss.454 SI performed the inspection while the plant was in operation and water was present in the pipes.455 In addition, SI performed ultrasonic inspections to measure the nominal wall thickness of each pipe segment and to prove-up specific guided wave testing results by quantifying the depth of corrosion at specific locations of interest.456 451 Entergy Testimony at 91 (A111) (ENTR30373).

452 Id.; see also Dec. 11, 2012 Tr. at 3608:20-21 (Lee).

453 Entergy Testimony at 91 (A111) (ENTR30373).

454 Structural Integrity Associates, Inc., G-Scan Assessment of 8 Condensate Water Storage Tank Return Line CD-183, Inspection Date: February 17th, 2009 at 1 (Mar. 19, 2009) (SI March 2009 Report) (ENT000579).

Guided wave ultrasonic testing is discussed further in paragraphs 176 to 179 below.

455 Id.

456 Id. In his revised rebuttal testimony, Dr. Duquette stated that the guided wave technology that Entergy used on the CST return line indicated an 85% loss of wall thickness but did not identify through-wall failure. New York Rebuttal Testimony at 15:10-14 (NYSR20399). Entergys witnesses disagreed with that statement. They explained the 85% through-wall loss indication corresponded to the actual leak location. Dec. 10, 2012 Tr. at 3451:13-20 (Cox); id. at 3451:23-25 (Azevedo) (That location, the 85 percent of wall loss, that was at the leak. And that pipe was replaced.). In fact, the guided wave testing assessment specifically states: Known leak verified at feature +F9 located 167 from the collar in the positive direction. SI March 2009 Report at 7 (ENT000579). Thus, the guided wave testing results in fact did assist in the identification of the leak location.

169. Mr. Azevedo and Mr. Lee stated that Entergy also identified two areas of thinned piping that exceeded minimum required wall thickness.457 Entergy replaced the pipe section containing the leak and performed weld repairs on the nearby areas that exhibited shallow corrosion.458 It also recoated the affected piping sections in accordance with Entergy procedures.459 170. Mr. Azevedo and Mr. Lee testified that, as part of its root cause evaluation, Entergy sent the failed pipe segment to a laboratory for analysis.460 It was determined that the direct cause of the event was a failure of the external protective pipe coating applied at the time of original construction, resulting in localized external corrosion of the pipe.461 Although the external pipe coating was correctly specified for the application, damage to the coating in this area of the pipe resulted in localized corrosion of the underlying metal.462 Specifically, Entergy determined that the root cause of the leak was the apparent inadvertent introduction of large rocks in the backfill during original construction that damaged the protective coating, ultimately leading to corrosion of the external piping surface and leakage from the pipe.463 High moisture in the soil surrounding the pipe also contributed to the corrosion, as the pipe was located at an 457 Entergy Testimony at 91 (A111) (ENTR30373).

458 Id.

459 Id.; see also Root Cause Analysis Report, CST Underground Recirc Line Leak, CR-IP2-2009-00666, Rev. 0 (May 14, 2009) (NYS000179).

460 Entergy Testimony at 91 (A111).

461 Id.

462 Id.

463 Id.

elevation that placed it in proximity to the water table.464 According to Mr. Azevedo and Mr.

Lee, damp or wet conditions accelerate the general corrosion of exposed carbon steel.465 171. In this regard, Mr. Azevedo emphasized that the CST return line corrosion was localized to a few square inches and did not involve extensive crevice corrosion on the order of several feet, as suggested by Dr. Duquette.466 Mr. Biagiotti also testified that crevice corrosion typically requires very oxygen-rich environments and, based upon his experience, has not been a major concern for piping that is direct-buried in soil.467 172. Mr. Azevedo and Mr. Lee testified that Entergy undertook numerous corrective actions based on an evaluation of the findings from this event.468 These correction actions are described in the 2009 Root Cause Report.469 For example, Entergy used improved backfill specifications to cover the pipe.470 NRC inspectors concluded that the actions Entergy implemented to evaluate and repair the leaking CST pipe were adequate and in accordance with the IP2 operating license.471 464 Id. at 91-92 (A111).

465 Id. at 92 (A111).

466 Dec. 11, 2012 Tr. at 3754:14-3755:2 (Azevedo).

467 Id. at 3755:3-20 (Biagiotti). Dr. Duquette agreed that deeper soils are more likely to have low oxygen contents and thus support lower corrosion rates. Id. at 3757:11-12 (Deeply buried pipes, I fully agree with Mr.

Biagiotti, low oxygen, low corrosion.).

468 Entergy Testimony at 92 (A111) (ENTR30373).

469 Id.; see also 2009 Root Cause Report at 33-35.

470 Entergy Testimony at 92 (A111) (ENTR30373); Dec. 11, 2012 Tr. at 3614:12-15 (Azevedo) (stating that current backfill specifications limit the size of the rocks in the backfill to either two or two and a half inches and limit the amount of organic material allowed in the backfill).

471 Entergy Testimony at 92 (A111) (ENTR30373); see also Letter from M. Gray, NRC, to J. Pollock, Entergy, Enclosure at 31-32 (May 14, 2009) (ENT000427).

173. According to the Entergy witness panel and Mr. Holston, the February 2009 CST return line leak resulted in no loss of an intended safety function for the piping at issue.472 Although Entergy declared the CST inoperable, the supply line from the CST to the AFW system remained in service and capable of fulfilling its safety function.473 If a reactor shutdown had occurred during this time, then the AFW system still would have delivered water from the CST to the steam generators.474 The ECCS also is available for core decay heat removal in the unlikely event that the AFW system does not function during an unexpected plant shutdown.475 174. In summary, the record indicates that Entergy appropriately evaluated the cause of the 2009 CST return line leak and took appropriate corrective actions in accordance with NRC requirements and plant procedures. Although Entergy initially declared the CST inoperable (an appropriate initial conservative position until further analyses could be conducted), the evidence indicates that the structural integrity requirements for the affect piping were met, and that there was no loss of intended safety function.

2. IPEC Direct and Indirect Inspections of Buried Piping Since 2009 175. The evidentiary record makes clear that the CST return line leak that occurred in February 2009 cannot be viewed in isolation. Since that time, Entergy has acquired substantial 472 Entergy Testimony at 92 (A112) (ENTR30373); NRC Staff Testimony at 61-62 (A53) (NRCR20016). PWRs such as IP2 generally rely upon the AFW system and the steam generators for core decay heat removal for all reactor shutdowns and accident conditions, except during a large loss-of-coolant accident, in which case the emergency core cooling system (ECCS) supplies water directly to the reactor coolant system for decay heat removal. Entergy Testimony at 92 (A112) (ENTR30373). At IP2, the AFW system supplies water to the steam generators in the event that the nonsafety-related main feedwater system, which normally maintains the water level in the steam generators during power operations, becomes unavailable. Id. The primary water supply for the AFW system is the condensate storage tank, which contains demineralized water. Id. A backup water supply is available at IP2 from the plants city water storage tank, which is filled with municipal water, but is maintained and operated onsite independent of the local city water system. Id.; see also Letter from Chairman G. Jaczko, NRC to Senator E. Markey, Encl. at 1 (June 17, 2009) (ENT000385).

473 Entergy Testimony at 93 (A112) (ENTR30373).

474 Id.

475 Id.

additional data and operating experience which do not indicate that degradation of in-scope buried piping or its coatings is widespread at IPEC, or that any buried piping metal loss due to external corrosion is occurring at an unacceptable rate. We summarize the additional data below.

a. September 2009 Guided Wave Testing of IP2 and IP2 Condensate and Service Water Piping 176. As a result of the plant-specific operating experience discussed above, Entergy contracted with SI to perform additional guided wave ultrasonic testing of buried piping at six locations.476 Guided wave testing is a low-frequency UT technique developed for the rapid survey of pipes to detect both internal and external wall loss in portions of buried piping that are difficult to access.477 It is used to confirm that significant corrosion has not occurred and to assess the need for further inspections of buried piping sections considered vulnerable to corrosion.478 476 Id. at 94 (A114); see also Structural Integrity Associates, Inc., G-Scan Assessment of Various Buried Piping (Nov. 16, 2009) (SI Guided Wave Testing Report) (ENT000428).

477 Entergy Testimony at 94-95 (A114) (ENTR30373). Guided wave testing uses multiple transducer arrays to direct sound energy in a circumferential mode, which creates a torsional guided wave within the pipe walls. Id.

These torsional waves propagate away from the transducer collar along the length of the pipe and reflect off features such as welds, supports, or areas of wall loss. Id. These reflections are collected and analyzed to identify specific locations along the pipe and the nature of the indications. Id.; see also Dec. 11, 2012 Tr. at 3738:3-3739:3, 3739:16-3740:11 (Biagiotti) (describing how guided wave testing works).

478 Entergy Testimony at 95 (A114) (ENTR30373). Dr. Duquette stated neither the NRC nor NACE views guided wave testing as a reliable inspection method. New York Rebuttal Testimony at 15:5-6 (NYSR20399). At hearing, Mr. Azevedo explained that Entergy is not crediting guided wave ultrasonic testing results as part of the 94 total excavated direct visual inspections to which Entergy has committed to perform. Dec. 11, 2012 Tr.

at 3863:3-10 (Azevedo). In addition, Mr. Biagiotti noted that Final LR-ISG-2011-03 states that [t]he use of guided wave ultrasonic or other advanced inspection techniques is encouraged for the purpose of determining those piping locations that should be inspected but may not be substituted for the inspections listed in the table. Dec. 11, 2012 Tr. at 3738:4-12 (Biagiotti) (quoting Final ISG-LR-2011-03, app. A at A-5 (NRC000162)). They also explained that this is exactly how Entergy has used guided wave testingas a screening tool to identify areas of potential concern that might warrant excavated direct visual inspections.

Dec. 11, 2012 Tr. at 3739:1-3 (Biagiotti) (stating that guided wave testing is widely used as a screening technology or indirect inspection method). Thus, Dr. Duquettes claim is immaterial insofar as Entergy is not crediting guided wave testing results as direct visual inspections, and the NRC recognizes the use of guided wave testing as a screening tool.

177. On September 22-23, 2009, SI used guided wave testing to test for wall loss at six locations on the IP2 and IP3 service water and condensate piping.479 IPEC engineers selected the locations for these inspections based on a determination that these locations have the highest risk of corrosion due to their proximity to the water table.480 178. The results of this guided wave testing investigation are documented in the SI Guided Wave Testing Report (ENT000428).481 The test evaluation criteria and test results are summarized in Table E2 and Table E3, respectively, of the report.482 Indications are on a scale of 1-4, with Level 1 indications being the most severe.483 179. Mr. Azevedo, Mr. Lee, and Mr. Biagiotti stated that the guided wave testing results indicated the presence of some Level 2 indications (i.e., areas of moderate interest) in the IP2 service water supply header piping and piping from the IP2/IP3 CST to the AFW pump building. No Level 1 indications (i.e., areas of substantial interest) were identified.484 SI recommended that the Level 2 indications, if reasonably accessible, be further explored with another NDE technique or direct visual examination.485 It also recommended that the Level 3 479 Entergy Testimony at 95 (A114) (ENTR30373).

480 Id.

481 The SI Guided Wave Testing Report (ENT000428) presents a detailed discussion of guided wave testing, including the necessary equipment, underlying physics, the methods used to interpret the test results, and the IPEC test results. Entergy Testimony at 95-96 (A114) (ENTR30373). The report contains illustrations and photos of the test locations and detailed descriptions of the test results. Id. at 96 (A114).

482 SI Guided Wave Testing Report at ES-1 to-2, tbls. E2 & E3 (ENT000428).

483 Id.

484 Entergy Testimony at 96 (A114) (ENTR30373).

485 Id.

areas be monitored over time.486 Accordingly, Entergy evaluated the Level 2 and 3 indications under the IPEC Corrective Action Program.487

b. Excavated Direct Visual Inspections of IPEC In-Scope Buried Piping Since 2009 180. As described in Entergys pre-filed testimony, since the 2009 CST return line leak, Entergy has performed a number of additional excavations and associated direct visual inspections of in-scope buried piping, including piping from the following systems: (1) AFW, which includes the CST lines (in 2009 and 2011); (2) city water (in 2009); (3) fire protection (in 2009 and 2011); and (4) service water (in 2011).488 These excavated direct visual inspections are described in detail in Entergys pre-filed testimony and supporting exhibits.489 181. With regard to CST piping, in December 2011, Entergy excavated and visually inspected approximately 12-foot linear segments of two IP3 buried piping lines (8-inch line COND-1080-1 and 12-inch line COND-1070-1) running from the condensate storage tank to the AFW building in accordance with in EN-EP-S-002-MULTI, Rev. 0, Buried Piping and Tanks General Visual Inspection (Oct. 30, 2009) (ENT000408).490 The coating on both lines was acceptable.491 The coating was removed for UT and guided wave testing examinations.492 There 486 Id.

487 Id. As discussed in Section IV.H of this decision, based on the guided wave testing results, Entergy developed plant modification packages to install cathodic protection on buried piping between the CST and the AFW buildings for both IP2 and IP3 (i.e., to protect the piping at the lower plant elevations, which are most susceptible to variations in the water table).

488 Id. at 97-99 (A115-18).

489 Id. The inspection reports for these excavated direct visual inspections and associated ultrasonic testing (UT) examinations were admitted into evidence as Exhibits ENT00430 to ENT000442. See Dec. 11, 2012 Tr. at 3630:2-8 (ONeill).

490 Entergy Testimony at 97 (A115) (ENTR30373).

491 Id.

492 Id.

were no signs of degradation of the base metal.493 The UT examinations confirmed that the wall thickness of both pipes exceeded 87.5% of the nominal wall thickness, and the guided wave testing examinations did not identify any areas of concern on either pipe.494 182. With regard to the buried city water and fire protection piping inspected in 2009 and 2011, the inspections found both the coating and piping condition acceptable per the acceptance criteria contained in EN-EP-S-002-MULTI (ENT000408).495 The backfill did not contain rocks or foreign material that could damage external coatings.496 183. The direct visual inspections of IP2 service water piping (24-inch lines 408 &

409) occurred in November and December 2011.497 Entergy exposed approximately 12 linear feet of each line, including 90-degree elbows.498 With the exception of some coating separation at one 90-degree elbow, the coating on both lines was in acceptable condition, as assessed under EN-EP-S-002-MULTI.499 The elbow with coating separation was stripped of coating and re-coated and taped.500 Entergy saw no corrosion of the exterior surface of the pipe, and direct UT 493 Id.; see also General Visual Inspection Report for IP3 AFW/Cond Return Line to CST (8-inch Line 1080)

(Ref. WO # 279578-03) (Dec. 2011) (ENT000430); General Visual Inspection Report IP3 CST supply to AFW Pumps (12-inch Line 1070) (Ref. WO # 279578-03) (Dec. 2011) (ENT000431).

494 Entergy Testimony at 97 (A115) (ENTR30373); see also UT Erosion/Corrosion Examination Report No. IP3-UT-11-076 (8 Line #1080, CST return line) (Dec. 2011) (ENT000432); UT Erosion/Corrosion Examination Report No. IP3-UT-11-077 (12 Line #1070, CST supply to the AFW pump section) (Dec. 2011)

(ENT000433).

495 Entergy Testimony at 98-99 (A116-A117) (ENTR30373); see also General Visual Inspection Report for 10-inch City Water Line from Catskill Water Supply (Oct. 2009) (ENT000434); General Visual Inspection Report for 16-inch City Water Line from CWST (Oct. 2009) (ENT000435); eneral Visual Inspection Report for 10-inch City Water/Fire Water Line at Maintenance Training Facility (MTF) (Nov. 2009) (ENT000436); General Visual Inspection Report for IP3 8-inch Fire Protection Line (N/S) at N/W corner of the WHUT Pit (Aug. 2011 (ENT000437); General Visual Inspection Report for IP3 6- inch Dire Protection Line (N/S) corner of the WHUT Pit (Aug. 2011) (ENT000438).

496 Entergy Testimony at 98-99 (A116-A117) (ENTR30373) 497 Id. at 99 (A118).

498 Id.

499 Id.

500 Id.

measurements showed the wall thickness at the site of coating separation to be greater than 87.5

% of the nominal wall thickness.501 No rocks or foreign material that would damage external coatings were observed.502 184. The inspectors also removed coating on straight sections of the service water piping (both lines 408 and 409) for direct UT measurement of pipe wall thickness and for guided wave collar installation.503 Direct UT results confirmed that wall thickness exceeded 87.5% of the nominal wall thickness.504 Guided wave testing inspections recorded a signal reflection about five feet downstream of the collar on Line 409.505 This location was excavated to expose the pipe, and then prepared for UT examination to determine the pipe wall thickness.506 IPEC completed the UT measurements in January 2012, and the measured wall thicknesses were at nominal (and thus acceptable) values.507 185. During the December 11, 2012 hearing session, Mr. Azevedo and Mr. Lee briefly discussed then-ongoing direct visual inspections of buried piping within an excavation in the IP2 501 Id.; see also General Visual Inspection Report for IP2 Service Water 24-inch Line 408 (WO #279576-02)

(Nov. 2011) (ENT000439); General Visual Inspection Report for IP2 Service Water 24-inch Line 409 (WO #279576-02) (Nov. 2011) (ENT000440); UT Erosion/Corrosion Examination Report No. IP2-UT-11-048 (Service Water 24-inch Line 408) (Dec. 2011) (ENT000441); UT Erosion/Corrosion Examination Report No.

IP2-UT-11-050 (Service Water 24-inch Line 409) (Dec. 2011) (ENT000448).

502 See General Visual Inspection Report for IP2 Service Water 24-inch Line 408 (WO #279576-02) (Nov. 2011)

(ENT000439); General Visual Inspection Report for IP2 Service Water 24-inch Line 409 (WO #279576-02)

(Nov. 2011) (ENT000440); UT Erosion/Corrosion Examination Report No. IP2-UT-11-048 (Service Water 24-inch Line 408) (Dec. 2011) (ENT000441); UT Erosion/Corrosion Examination Report No. IP2-UT-11-050 (Service Water 24-inch Line 409) (Dec. 2011) (ENT000448).

503 Entergy Testimony at 99-100 (A118) (ENTR30373).

504 Id.

505 Id.

506 Id. at 100.

507 Id; see also UT Erosion/Corrosion Examination Report No. IP2-UT-12-002 (Service Water 24-inch Line 409)

(Jan. 2012) (ENT000442); Condition Report CR-IP2-2011-06248 (Dec. 8, 2011) (ENT000443); Condition Report CR-IP2-2011-06250 (Dec. 8, 2011) (ENT000444).

transformer yard.508 Mr. Lee indicated that these inspections included some coated carbon steel piping within the scope of license renewal.509 Mr. Azevedo stated that Entergy had observed some coating degradation during the direct visual inspections of the piping, but no evidence of any significant corrosion of the piping.510 He further stated that Entergy planned to do some ultrasonic testing of this buried piping.511 186. At the hearing, Mr. Azevedo stated that Entergy had completed fourteen (14) of the twenty (20) planned pre-PEO direct visual inspections of IP2 in-scope buried piping, and four (4) of the fourteen (14) planned pre-PEO direct visual inspections of IP3 in-scope buried piping.512 In a Joint Declaration (ENT000607) filed subsequent to the hearing, Mr. Azevedo stated that since the hearing in December 2012, Entergy had completed six (6) excavated direct visual inspections of code class/safety-related buried piping within the scope of license renewal in the IP2 transformer yard.513 With these recently completed inspections in the IP2 transformer yard, Entergy has now completed all twenty (20) of the excavated direct visual inspections of IP2 in-scope buried piping that are required before entering the PEO.514

c. November 2010 SI Area Potential Earth Current (APEC) Survey 187. In 2010, Entergy also commissioned SI to conduct a site-wide APEC survey within the protected area at IPEC. The APEC survey of buried piping systems provides information on the condition of multiple buried pipes in an area. It uses an accepted cathodic 508 See Dec. 11, 2012 Tr. at 3798:13-3799:23 (Azevedo), 3806:1-8 (Azevedo), 3864:3-20 (Lee).

509 Id. at 3864:11-15 (Lee).

510 Id. at 3806:1-9 (Azevedo).

511 Id. at 3806:4-6 (Azevedo).

512 Id. at 3869:4-5, 7-8 (Azevedo).

513 March 2013 Joint Declaration at ¶ 13 (ENT000607).

514 Id. at ¶ 14.

protection industry data collection technique to evaluate the corrosion potential (corrosion cells are observed where coating degradation allows anodes and cathodes to interact through a soil electrolyte) and the cathodic protection effectiveness on buried piping systems.515 SI completed the APEC survey in November 2010. The final technical report was approved by Entergy in November 2011.516 188. SI performed two data collection activities as part of the APEC surveys at IPEC:

(1) a native survey and (2) an interrupted cathodic protection current survey, and then integrated the results for interpretation.517 A total of 335 APEC test locations were monitored throughout the protected area at IPEC.518 These locations encompass approximately fifty-four percent of the IPEC buried piping that is within the scope of license renewal.519 189. The native APEC survey results indicated that adequate polarization (>100 mV) was present around IP2 near the CST and intake structure, partially due to the sacrificial protection afforded by the galvanized security fencing for the former and the impressed current cathodic protection system for the latter.520 The remainder of the plant was not similarly polarized due to the absence of an influence from a cathodic protection system in the vicinity of IP1 and IP3.521 However, the native APEC survey results did not reveal extensive current flows; i.e., conditions that could indicate active external corrosion cells in the absence of cathodic 515 See Report No. 0900271, Rev. 0, Indian Point Energy Center APEC Survey at 2-4 to 2-7 (Nov. 27, 2011)

(APEC Survey Report) (ENT000445); Dec. 11, 2012 Tr. at 3778:21-3780:19 (Biagiotti) (providing an overview of the APEC survey methodology and interpretation of results).

516 See APEC Survey Report (ENT000445).

517 See id. at 1-1, 3-1 to 3-16.

518 See id. at 1-1, 2-8.

519 Dec. 11, 2012 Tr. at 3782:24-3783:1 (Biagiotti).

520 Id. at 3785:5-10 (Biagiotti); Entergy Testimony at 103 (A119) (ENTR30373); APEC Survey Report at 1-1, 2-1, 3-5, 3-12 (ENT000445).

521 Entergy Testimony at 103 (A119) (ENTR30373); APEC Survey Report at 3-5 (ENT000445).

protection.522 According to Mr. Biagiotti, whose firm (SI) performed the APEC survey, these results indicate that coating degradation, if present, is limited.523 Additionally, when the installed cathodic protection near the IP2 intake structure was applied (i.e., turned on), the data showed that sufficient current is applied at the IP2 intake to effectively control corrosion at sites where there may be minor coating degradation.524 190. Dr. Duquette did not comment on the APEC survey results in his pre-filed rebuttal testimony.525 Nor did he object to the use of the APEC method.526 However, at the hearing, Dr.

Duquette stated that he was surprised by the amount of current flow detected by the APEC survey, and noted that he would expect no current at all.527 Mr. Biagiotti responded by explaining that IPEC subsurface environment is a mixed-metal environment containing zinc-coated or galvanized conduits (e.g., storm sewers and corrugated metal pipe).528 Therefore, he noted, some current flow should be expected because zinc (the galvanizing material) functions as an anode material in the presence of steel.529 191. Based on the APEC survey results, SI recommended that Entergy perform direct excavated visual inspections at four locations showing higher current flows to further assess the piping condition.530 Those recommended dig locations are shown in Figures 3-10 to 3-13 and 522 Dec. 11, 2012 Tr. at 3786:1-8 (Biagiotti); Entergy Testimony at 103 (A119) (ENTR30373).

523 Dec. 11, 2012 Tr. at 3606:14-23, 3789:5-8 (Biagiotti); Entergy Testimony at 103 (A119).

524 Dec. 11, 2012 Tr. at 3787:21-3788:14 (Biagiotti); Entergy Testimony at 103 (A119). As Mr. Biagiotti noted, SI performed the APEC survey in November 2010, prior to the installation of the new IP2 and IP3 CST line cathodic protection systems in 2012. Dec. 11, 2012 Tr. at 3787:24-3788:1 (Biagiotti).

525 See generally New York Rebuttal Testimony (NYSR20399).

526 With regard to APEC, Dr. Duquette stated: I believe very strongly that the technique is a very good one, and works very well. Its been proven in a lot of other industries. Dec. 11, 2012 Tr. at 3822:11-14 (Duquette).

527 Id. at 3791:21-3793:5 (Duquette).

528 Id. at 3793:83794:20 (Biagiotti).

529 Id. at 3794:2-10 (Biagiotti).

530 Id. at 3786:23-3787:1-4 (Biagiotti).

Figure 4-2 of the APEC Survey Report.531 Mr. Azevedo stated that Entergy considered SIs recommendations in planning excavated direct visual inspections of buried piping, and that Entergy has completed excavated direct visual inspections in locations near Dig Locations 1 and 2 (as shown in Figure 4-2 of the APEC Survey Report). Specifically, the recently-completed direct visual inspections of buried piping in the IP2 transformer yard were located near Dig Location 1. The December 2011 direct visual inspections of buried IP3 CST piping running from the condensate storage tank to the AFW building were located near Dig Location 2.

According to Mr. Cox. Mr. Lee, and Mr. Azevedo, Entergy chose to excavate locations not directly over proposed Dig Locations 1 and 2 in order to maximize the amount of in-scope, safety-related piping inspected and to verify that the in-scope piping is not corroding.532 Mr.

Azevedo stated that, in the future, Entergy likely would excavate directly above at least some of the four dig locations identified by SI.533 He further noted that Entergy planned to excavate Dig Location 3 in 2013, but did not have immediate plans to excavate Dig Location 4 due to the absence of in-scope buried piping in that location.534

3. Summary of IPEC Soil Testing Data 192. Dr. Duquette claimed that Entergys own studies show that the soils at IPEC are mildly to moderately corrosive, warranting cathodic protection as an objective matter.535 Dr.

531 See APEC Survey Report at 3-13 to -16, 4-3 (ENT000445). The four locations are identified in the APEC Survey Report as Unit 2 Transformer Yard (Dig Location 1), Unit 3 Transformer Yard (Dig Location 2), West of Unit 3 Heater Bay (dig Location 3), and South of Cafeteria (Dig Location 4).

532 Dec. 11, 2012 Tr. at 3825:4-19 (Cox), 3798:14-22 (Azevedo), 3798:24-3799:10 (Azevedo).

533 Id. at 3803:19-3804:7 (Azevedo).

534 Id. at 3799:11-14 (Azevedo).

535 New York Direct Testimony at 22:13-16 (NYS000164).

Duquette based this claim on soil resistivity data contained in a report prepared in 2008 by an Entergy vendor, PCA Engineering, Inc. (PCA).536 193. By way of background, in October 2008 PCA performed a corrosion/cathodic protection field survey and assessment of underground structures at IPEC.537 These buried and underground structures included structures both within and outside the scope of the license renewal rule.538 The investigation included a review of site drawings and a site survey that included soil resistivity measurements, structure-to-soil potential measurements, electrical isolation testing, and temporary impressed current testing.539 194. PCA issued a report on November 10, 2008, and a revised version thereof on December 2, 2008.540 Sections VI and VII of the PCA Report summarize the investigation results and PCAs recommendations.541 Most relevant here, PCA recorded soil resistivity data for the areas above the buried piping running between the IP2 CST and the AFW pump building, and the IP2 city water storage tank to the IP2 pipe tunnel.542 Soil resistivities were determined at depths of five, ten, and fifteen feet below ground surface, as summarized in Table 7 of Entergys pre-filed testimony.543 536 See Engineering Report No. IP-RPT-09-00011, Rev. 0, Corrosion/Cathodic Protection Field Survey and Assessment of Underground Structures at Indian Point Energy Center Unit Nos. 2 and 3 during October 2008 (Dec. 2, 2008) (PCA Report) (NYS000178).

537 Entergy Testimony at 100 (A119) (ENTR30373).

538 Id.

539 Id.

540 See id.

541 See PCA Report at 10-18 (NYS000178).

542 See Corrosion Field Survey Data and Tables appended to the PCA Report (NYS000178). The soil resistivity data are summarized and discussed in Answer 128 of Entergys pre-filed testimony (ENTR30373).

543 Entergy Testimony at 116 (A129) (ENTR30373).

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195. Entergys experts disagreed with Dr. Duquettes characterization of the data.

They explained that, although interpretation of soil resistivity values can vary among corrosion engineers, a generally accepted guide is follows: soil resistivity values from 1000 - 2000 ohm-cm indicate moderately corrosive conditions; values from 2000 to 10,000 ohm-cm indicate mildly corrosive conditions; and values above 10,000 ohm-cm indicate negligible corrosivity.544 The lowest value recorded by PCA is 8043 ohm-cm, which is well above the 2000 ohm-cm threshold for moderately corrosive soil.545 The other eleven readings all were above 10,000 ohm-cm, which indicates that the soil has a negligible degree of corrosivity.546 196. At the hearing, Dr. Duquette stated that he agrees with the NACE guidelines reflected in Entergys pre-filed testimony,547 and that soil resistivity readings above 10,000 ohm-cm are not very corrosive.548 He also agreed that the 2008 PCA soil resistivity tests showed only one reading (8043 ohm-cm) in the mildly corrosive range.549 197. As discussed during the hearing, in November and December 2011, Entergy performed additional soil resistivity testing on five soil samples taken from locations in the vicinity of the IP2 and IP3 AFW buildings and IP2 Service Water 24-inch Line 40.550 The 544 Id. at 117 (A129).

545 Id.

546 See id. at 116, tbl. 7 (A129). As another point of reference, Entergys witnesses noted that Table 9-1 of the API 570 piping inspection code recommends a 10-year inspection frequency for buried piping without effective cathodic protection where soil resistivity values are between 2000 to 10,000 ohm-cm, because these values do not yield high corrosion rates. API 570, Piping Inspection Code: In-Service Inspection, Rating, Repair, Alteration of Piping Systems, American Petroleum Institute, 2d Ed (Oct. 1998) (ENT000447).

547 See Entergy Testimony at 117 (A129) (ENTR30373) (duplicating Table 5.5 from Peabodys Control of Pipeline Corrosion, at 88 (ENT000390), which is based on NACE soil resistivity guidelines).

548 Dec. 11, 2012 Tr. at 3813:24-3814:2 (Duquette).

549 Id. at 3814:5-7 (Duquette); see also id. at 3851:11-12 (Duquette) ([M]ost of their soil is fairly high resistivity.).

550 Dec. 11, 2012 Tr. at 3811:16-22 (Lee), 3816:25-3817:6 (Biagiotti).

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measured soil resistivities ranged from 27,000 to 99,000 ohm-cm.551 Thus, of the seventeen total soil resistivity measurements made in 2008 and 2011, all values except one exceeded 10,000 ohm-cm, and the vast majority of the values exceeded 20,000 ohm-cm. This is consistent with the statement in the IP2 and IP3 FSARs that the majority of soil resistivity readings taken at the time of original plant construction were above 10,000 ohm-cm.552 198. The evidence discussed above does not support Dr. Duquettes claims that soil conditions at IPEC warrant the installation of cathodic protection. The soil testing data discussed above do not indicate the presence of aggressive soils. Entergy has committed to collect and analyze additional soil samples before the PEO and at least once every ten years thereafter to confirm that the soil conditions in the vicinity of in-scope buried pipes remain non-aggressive.553 If any areas of concern are identified during future inspections or testing, then the issues will be placed into the corrective action program for evaluation of extent of condition and appropriate corrective action and preventive measures, including additional excavated direct visual inspections of in-scope buried piping.554 Finally, as discussed below, Entergy is evaluating the need for cathodically protecting specific buried piping segments at IPEC based on plant-specific operating experience and inspection results, and already has installed three targeted cathodic protection systems since 2009.555 551 Id. at 3817:1-6 (Biagiotti); GZA/Theielsch Engineering Soil Resistivity Data for IP2 & IP3 AFW Bldg, IP2 SW Line 408 (June 2012) (ENT000582).

552 Entergy Testimony at 116 (129) (ENTR30373); see also id. at 112 (A125) (citing IP2 UFSAR, Rev. 20

§ 5.1.3.12 (NYSR0014D); IP3 UFSAR, Rev. 20 § 16.4.4 (NYSR0013K)); see also Dec. 11. 2012 Tr. at 3843:12-17 (Biagiotti).

553 Entergy Testimony at 117(129) (ENTR30373).

554 Id. at 85 (A104), 117 (A129); Dec. 11, 2012 Tr. at 3694:5-12 (Azevedo).

555 Entergy Testimony at 110 (A123).

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4. Board Conclusions Based on Review of Available IPEC Operating Experience 199. In conclusion, the Boards review of the available IPEC-specific operating experience indicates that there have not been any significant failures (i.e., failure to provide pressure boundary integrity such that adequate flow and pressure cannot be delivered) of in-scope buried piping.556 Apart from some localized coating degradation, the only significant degradation of in-scope piping at IPEC was that associated with the leakage from the CST return line in February 2009.557 Numerous excavated direct visual inspections performed since that time have not revealed any significant metal loss or poor backfill quality.558 Further, the available data, including the soil resistivity and corrosion potential data obtained from the 2008 PCA and 2009 APEC surveys, respectively, indicate that the soil generally is non-corrosive, and that any degradation of potentially exposed buried piping is progressing at a slow rate.559 H. Current Use and Status of Cathodic Protection at the IPEC Site 200. In its position statements and testimony, New York focused heavily on the asserted need for site-wide cathodic protection at IPEC.560 Dr. Duquette claimed that there are no cathodic protection systems in operation at IPEC for safety-related buried piping, and that 556 As discussed at hearing, IPEC experienced a leak from an auxiliary steam line in 2007, but that piping is not in-scope for license renewal and was not coated in the same fashion (coat tar epoxy) as pipes within the scope of the BPTIP. Dec. 10, 2012 Tr. at 3366:11-13 (Holston); id. at 3367:14-22, 3406:21-25 (Cox); id. at 3621:8-9 (Lee).

557 See Dec. 11, 2012 Tr. at 3947:23-3948:8 (Azevedo) (We have done a significant number of inspections, by that I mean direct visual inspections by excavating the pipe and looking at the condition of the soil, condition of the coating, and taking UT measure[ments] where appropriate. And aside from the 2009 leak, we have found no significant issues on these other locations that we inspected. . . .).

558 See id. at 3948:6-8 (Azevedo) (But, in general, the soil has been good, the coating has been in generally good condition, and we found no significant issues.).

559 See Entergy Testimony at 119 (A133) (ENTR30373).

560 See, e.g., New York Position Statement at 53 (stating that Energys AMP is inadequate because it does not require cathodic protection) (NYSR00163); New York Rebuttal Position Statement at 18-19 (NYS000398);

New York Rebuttal Testimony at 14:17-19 (Increased frequency of inspections does not replace the requirement for cathodic protection .) (NYSR20399).

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Entergy has no plans to either re-commission the existing inoperative systems or to install new systems.561 201. Dr. Duquettes claims clearly lack evidentiary support. Entergy has installed several cathodic protection systems on selected buried piping systems since 2009, and has stated its intent to install additional cathodic protection, as warranted.562 For example, Entergy installed cathodic protection on portions of the IP2 and IP3 city water lines in November 2009 based on the recommendations of a vendor (i.e., PCA).563 Specifically, PCA recommended that Entergy take action to eliminate/minimize the stray current (i.e., current through paths other than the intended circuit) affecting the city water piping where that piping crosses over the Algonquin natural gas pipeline.564 Entergy installed the cathodic protection system in November 2009 to resolve the stray current issue and protect the affected portions of the IP2 and IP3 city water lines.565 202. Additionally, based on the results of the September 2009 guided wave inspections discussed above, Entergy also installed cathodic protection on two IP2 CST lines and two IP3 CST lines.566 561 Duquette Report at 24 (NYS000165).

562 Dec. 11, 2012 Tr. at 3736:2-14 (Azevedo) (explaining that IPEC does not have a site-wide cathodic protection system, but that the site has installed, and continues to install, cathodic protection on an as-needed basis).

563 Entergy Testimony at 110 (A123) (ENTR30373).

564 See PCA Report at 12-13, 16-17 (NYS000178); Dec. 11, 2012 Tr. at 3709:2-6 (Lee); see also Dec. 11, 2012 Tr. at 3750:1-21 (Biagiotti) (explaining concept of stray current).

565 See Dec. 11, 2012 Tr. at 3846:13-15 (Azevedo). Dr. Duquette testified that he had no concerns regarding stray current corrosion at IPEC. Id. at 3751:10-16 (Duquette). With respect to the Algonquin gas pipeline, he stated: In fact, they detected a stray current problem and fixed it. Id. at 3752:6-7 (Duquette).

566 Entergy Testimony at 110 (A123) (ENTR30373); see also Dec. 11, 2012 Tr. at 3847:6-23 (Azevedo). The specific lines are IP2 CST Lines #1505 and #1509 (12-inch to AFW and 8-inch return to the CST, respectively), and IP3 CST #1070 and #1080 (12 to AFW and 8-inch return to AFW, respectively). During the hearing, Mr. Azevedo clarified that Entergy had installed the physical elements of the IP3 CST cathodic

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203. Entergy also has identified other locations for future installation of new cathodic protection systems, including the IP2 Service Water Line #408 (24-inch main supply headers) and the IP3 Dock Sheet Piling just south of the intake Structure.567 Mr. Azevedo and Mr. Lee testified that Entergy has initiated an engineering modification for the IP2 service water line cathodic protection system, which is expected to be installed before or shortly after the IP2 PEO begins.568 204. Therefore, the Board finds no reasonable basis for Dr. Duquettes claim that IPEC has no cathodic protection on safety-related systems, and that Entergy has no intention to install new systems when warranted by available technical data and operating experience. The safety-related systems within the scope of the BPTIP and NYS-5 (i.e., those systems that contain or may contain radioactive fluids) include the safety injection, service water, and AFW systems.

The safety injection system is corrosion-resistant (and also coated) stainless steel and does not warrant cathodic protection per NRC or industry guidance. And, as stated above, Entergy has installed cathodic protection systems on portions of the IP2 and IP3 CST lines that are part of the AFW systems, and plans to install cathodic protection on a portion of the IP2 service water piping.569 205. Dr. Duquette also claimed that SEP-UIP-IPEC (the IPEC Underground Components Inspection Plan) states that many buried or underground lines at IPEC were once cathodically protected, but that such cathodic protection systems have lapsed, accelerating protection system, but still was adjusting the system to meet the relevant NACE standards. Dec. 11, 2012 Tr.

at 3849:5-8 (Azevedo).

567 Entergy Testimony at 110 (A123) (ENTR30373); see also Dec. 11, 2012 Tr. at 3848:19-25 (Azevedo).

568 Entergy Testimony at 110 (A123) (ENTR30373).

569 Id. at 111 (A124). As discussed above, Entergy performed direct visual inspections and UT examinations of sections of the IP2 service water piping (24-inch lines 408 and 409) in November and December 2011, albeit at different locations than those identified for future cathodic protection. Those inspections revealed no corrosion on the piping examined. Id.

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external corrosion where the coating has failed.570 In a related vein, Dr. Duquette asserted that Entergy has not committed to taking certain actions identified in fleet procedure EN-DC-343 at IPEC despite knowing for years that its cathodic protection systems had fallen into disrepair, and has not committed to repairing them now.571 206. The Board again finds no support in the record for Dr. Duquettes claims. As discussed above, SEP-UIP-IPEC documents the site-specific review of IPEC buried piping and provides details on the risk assessment of the buried piping identified at the site. The particular statement in SEP-UIP-IPEC cited by Dr. Duquette pertains generally to Entergy fleet cathodic protection systems and is not specific to IPEC.572 Although SEP-UIP-IPEC indirectly acknowledges the prior installation of cathodic protection systems at IPEC, those systems generally were not installed to provide cathodic protection to buried piping at the site. Rather, they were installed to provide protective current to the docks and discharge canal.573 Thus, the existing inoperative cathodic protection systems, as Dr. Duquette called them, were not installed to protect buried piping.574 207. Section 5.1.3.12 and Section 16.4.4 of the IP2 and IP3 FSARs, respectively, confirm this fact. They indicate that when IP2 and IP3 were built, it was determined that cathodic protection was not required on underground facilities in areas away from the river or the containment building liner, although a protective coating on pipes was recommended to 570 Duquette Report at 16 (ENT000165).

571 Id.

572 SEP-UIP-IPEC, Rev. 0 at 14 (NYS000174) (referring to most Entergy plants cathodic protection systems).

573 See Entergy Testimony at 113 (A125) (ENT30373); APEC Survey Report at 1-1, 3-5 (ENT000445); Dec. 11, 2012 Tr. at 3785:5-10, 3788:2-6 (Biagiotti).

574 Duquette Report at 24 (NYS000165).

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eliminate any random localized corrosion attack.575 As a result, only a limited amount of cathodic protection on the IP2 circulating and service water system buried piping near the Hudson River was installed during initial construction.576 208. SEP-UIP-IPEC recommends the conduct of an APEC survey to analyze and implement needed improvements to the corrosion control (coatings) and cathodic protection effectiveness of the station.577 As discussed earlier, Entergy performed an APEC survey at IPEC in November 2010. As required by the UPTIMP and BPTIP, Entergy is performing, and will continue to perform, such inspections.

209. The Board finds Entergys approach to cathodic protection is technically sound.

In this regard, we are persuaded by the testimony of Mr. Biagiotti and other Entergy witnesses, who explained that at established, complex sites such as IPEC (which has an extensive network of buried pipes), a progressive or targeted approach to the retrofitting of cathodic protection systems (as discussed in paragraph 210 below) is prudent.578 Wholesale site-wide retrofits generally are recommended only when upgrading existing cathodic protection infrastructure or when widespread, significant degradation is observed.579 Neither scenario applies in the case IPEC.

210. Rather, because IPEC is an existing plant without site-wide cathodic or evidence of widespread coating degradation, the technically sound approach is to increase monitoring of buried piping to detect coating degradation, and then to install cathodic protection systems in 575 IP2 UFSAR, Rev. 20, § 5.1.3.12 (NYSR0014D); IP3 UFSAR, Rev. 20, § 16.4.4 (NYSR0013K); Dec. 11, 2012 Tr. at 3843:12-17 (Biagiotti).

576 Dec. 11, 2012 Tr. at 3843:18-23 (Biagiotti).

577 SEP-UIP-IPEC, Rev. 0 at 14 (NYS000174).

578 See Entergy Testimony at 115 (A128); see also Dec. 11, 2012 TR. at 3892:14-3893:9 (Biagiotti) (discussing the practical challenges associated with installing cathodic protection system at a site like IPEC).

579 See Entergy Testimony at 115 (A128)

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targeted areas to control any detected degradation, as needed.580 Entergy is following this approach, consistent with PCA recommendations and best industry practices.581 For these reasons, the Board is not persuaded by Dr. Duquettes contrary argument that installation of site-wide cathodic protection is far more practical than Entergys planned inspections. Regardless, we find that the numerous direct visual inspections of buried piping and confirmatory soil testing that Entergy has committed to perform provide reasonable assurance that the effects of aging on in-scope buried components will be adequately managed during the PEO.

211. Finally, Entergys witnesses (Azevedo, Cox, Lee, and Ivy) stated that fleet procedure EN-DC-343 requires the maintenance and/or upgrading of cathodic protection systems.582 As such, corrective actions to repair, maintain, and operate existing cathodic protection systems have been implemented in accordance with the IPEC Correction Action Program.583 For example, annual cathodic protection equipment checks and/or adjustments are 580 See id; see also NACE SP0169-2007 at 3 (ENT000388); PCA Report at 14-18 (NYS000178); Dec. 11, 2012 Tr. at 3777:24-3778:2) (Biagiotti) (stating that Entergy has supplemented coatings with cathodic protection system upon finding evidence of degraded coatings); Dec. 11, 2012 Tr. at 3860:19-3861:2, 3861:19-25 (Holston) (discussing Entergys recent and planned installation of targeted cathodic protection systems at IPEC).

581 Dec. 10, 2012 Tr. at 3452:4-8 (Azevedo) (noting Entergys recent installation of targeted cathodic protection systems and plans to install additional systems). In his direct testimony, Dr. Duquette suggested that Entergy had ignored the recommendations set forth in the November 2008 PCA Report. See New York Direct Testimony at 22:8-24:6 (NYS000164); New York Position Statement at 56 (NYSR00163); see also PCA Report at 16-18 (NYS000178). The Board disagrees. The record shows that Entergy has followed all three of these recommendations by installing cathodic protection on the city water piping in 2009, identifying and installing (or planning to install) cathodic protection systems on those in-scope buried piping segments most susceptible to corrosion, and by developing and implementing a risk-informed inspection program that is consistent with current NRC and industry recommendations. See Entergy Testimony at 114-15 (A128)

(ENTR30373); Dec. 11, 2012 Tr. at 3715:11-3716:9 (Azevedo).

582 Entergy Testimony at 109 (A123) (ENTR30373); Dec. 11, 2012 Tr. at 3955:20-25 (Azevedo) (discussing Entergys performance of annual inspection of cathodic protection systems and monitoring/logging of cathodic protection system rectifier outputs).

583 Entergy Testimony at 109 (A123) (ENTR30373).

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conducted annually by NACE-qualified inspectors.584 These practices are consistent with EPRI guidelines.

I. New Yorks Claims that NRC and Industry Guidance Documents Require the Installation of Cathodic Protection Lack Merit 212. Dr. Duquette asserted that the BPTIP is inadequate because it does not require cathodic protection in accordance with NRC Staff guidance in NUREG-1801, Rev. 2, AMP XI.M41, as modified by LR-ISG-2011-03.585 Mr. Holston, who is the primary author of Final LR-ISG-2011-03, explained why that is not the case.

213. As an initial matter, only NRC regulations, not guidance documents, impose legally binding requirements.586 In this case, NRC regulations do not require the use of cathodic protection systemseither during the initial operating period or during the PEO.587 214. Furthermore, NUREG-1801, Rev. 2, AMP XI.M41, as revised by Final LR-ISG-2011-03, explicitly recognizes that cathodic protection is not available at all plants, and that other measures may be taken to protect buried piping and tanks without cathodic protection.588 Specifically, NUREG-1801, Rev. 2, AMP XI.M41 provides that soil sampling and augmented inspections constitute an acceptable alternative to installing site-wide cathodic protection.589 584 Id.

585 Dec. 11, 2012 Tr. at 3725:13-16 (Duquette).

586 Yankee Atomic Elec. Co. (Yankee Nuclear Power Station), CLI-05-15, 61 NRC 365, 375 n.26 (2005) (We recognize, of course, that guidance documents do not have the force and effect of law.) (citations and internal quotation marks omitted).

587 See NRC Staff Testimony at 36-37 (A29) (NRCR20016) (accepting Entergys use of preventative actions to compensate for the lack of site-wide cathodic protection).

588 See Final LR-ISG-2011-03 at 3 (NRC000162) (Table 4a, Inspections of Buried Pipe, was revised to reflect the recommended number of inspections when cathodic protection will not be provided during the [PEO] for systems or portions of systems within the scope of license renewal.) (emphasis added).

589 Id. (stating that for those plants without cathodic protection in use during the PEO increased inspections were necessary to provide reasonable assurance that the components will meet their [CLB] functions throughout the period of extended operation).

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215. As discussed in Section IV.C.3, supra, the NRC Staff issued RAIs to Entergy to allow the Staff to consider the adequacy of the BPTIP relative to the key recommendations in NUREG-1801, Rev. 2, AMP XI.M41. Mr. Holston stated that IPEC would fall within Final LR-ISG-2011-03 inspection Category F (which assumes no existing site cathodic protection), for which the Staff recommends a total of ninety-one (91) inspections for a two-unit site during years thirty to sixty of the plants operation.590 The comparable inspection quantities planned for IPEC are ninety-four (94) (for soil that is non-corrosive) and 118 (for soil that is corrosive).591 Thus, the number of inspections at IPEC actually exceeds the number of inspections recommended in Final LR-ISG-2011-03 and, in the Staffs view, is sufficient to provide reasonable assurance in the absence of site-wide cathodic protection.592 216. In rebuttal, Dr. Duquette asserted that Entergy has not justified the lack of site-wide cathodic protection at IPEC in accordance with NUREG-1801, Rev. 2, AMP XI.M41.593 The relevant portion of AMP XI.M41 states that [t]he justification should include sufficient detail (e.g., soil sample locations, soil sample results, the methodology and results of how the overall soil corrosivity was determined, pipe-to-soil potential measurements) for the staff to independently reach the same conclusion as the applicant.594 It further states that an exception must be stated and justified if the basis for not providing cathodic protection is other than 590 NRC Staff Testimony at 60 (A52) (NRCR20016).

591 Id.

592 Id. Mr. Holston noted that he has evaluated buried piping AMPs for four plants that do not have site-wide cathodic protection, and that Entergys planned number of inspections is on the high end. Dec. 11, 2012 Tr.

at 3872:2-5 (Holston).

593 New York Rebuttal Testimony at 14:13-20 (NYSR20399).

594 Final LR-ISG-2011-03, app. A at A-3 (NRC000162).

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demonstrating that external corrosion control is not required, or demonstrating that installation, operation, or surveillance of a cathodic protection system is not practical.595 217. As discussed previously, Entergy filed its LRA in April 2007, several years before the Staff issued AMP XI.M41 and LR-ISG-2011-03. Therefore, Entergy appropriately referenced NUREG-1801, Rev. 1 AMP XI.M34 in its LRA, and did not need to state and justify an exception to the yet-to-exist NUREG-1801, Rev. 2 AMP XI.M41.596 As Mr. Holston noted, however, the NRC Staff issued an RAI to Entergy requesting that it justify why the number of planned inspections of in-scope buried steel piping systems that are not cathodically protected is sufficient to reasonably assure that the piping will continue to meet or exceed the minimum design wall thickness during the PEO.597 Entergy responded to that RAI in a docketed submittal (NL-11-032) dated March 28, 2011.598 218. The Board finds that Entergy has provided the technical justification sought in paragraph 2.a.iii. of AMP XI.M41 in its March 28, 2011 RAI response, as well as in other documents that have been admitted into evidence. In short, Entergy has: (1) established that all in-scope buried piping was coated in accordance with AWWA C-203-62 (see Section IV.F.3);

(2) described its soil testing locations, methods, and results (see Sections IV.F.3 and IV.G.3); (3) described its buried piping risk ranking methodology and results (see Section IV.F.4); (4) performed numerous indirect inspections (e.g., structure-to-soil potential measurements, guided wave testing, the APEC survey) of in-scope buried piping (see Section IV.G.2); (5) performed numerous excavated direct visual inspections and ultrasonic testing of in-scope buried piping 595 Id.

596 Dec. 11, 2012 Tr. at 3854:11-16, 23-25 (Holston).

597 Id. at 3855:8-15 (Holston).

598 See NL-11-032 (NYS000151).

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(see Section IV.G.2); and (6) committed to perform additional excavated direct visual inspections and soil testing in accordance with Final LR-ISG-2011-03 recommendations (see Section IV.C.3).

219. The available soil resistivity, corrosion potential, and other data obtained from the aforementioned activities indicate that IPEC site soils generally are non-corrosive, and that any degradation of potentially exposed buried piping is progressing slowly.599 Further, the excavated direct visual inspections performed to date do not indicate that coating degradation, poor backfill quality, or metal loss are systemic issues at IPEC.600 Thus, ample data support the conclusion that site-wide cathodic protection is not necessary. As Mr. Holston stated: Based on this information, there is no compelling reason why installation of a cathodic protection system is required to adequately manage the aging of buried piping and tanks for the IP2/IP3 LRA.601 Nonetheless, Entergy has installed cathodic protection, when prudent based on site-specific conditions and operating experience.602 The Board finds this approach to be reasonable and technically justified.

220. Referring to NEI 09-14, Rev. 1 and EPRI 1016456, Dr. Duquette also argued that both documents recommend cathodic protection for critical piping systems, such that Entergys BPTIP fails to meet the industry standard of care.603 That argument is factually unsupported.

599 Entergy Testimony at 119 (A133) (ENTR30373).

600 Id.; see also Dec. 11, 2012 Tr. at 3947:23-3948:1-8 (Azevedo); id. at 3948:13-16 (Azevedo) (The results of these inspections have given me assurance that the buried pipes at Indian Point are in good condition and will perform their intended function.).

601 NRC Staff Testimony at 63-64 (A55) (NRCR20016). Mr. Holston and Mr. Biagiotti also testified that site-wide cathodic protection is not practical at IPEC because IP2 and IP3 are essentially built on bedrock. See Dec. 11, 2012 Tr. at 3856:5-13 (Holston); id. at 3892:17-25 (Biagiotti) (stating that a deep well cathodic protection system is not practical at IPEC given the sites geology).

602 Entergy Testimony at 94 (A113) (ENTR30373).

603 New York Position Statement at 19 (NYSR00163).

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NEI 09-14 and EPRI 1016456 recommend only that if a cathodic protection system exists, then it should be properly tested and maintained.604 Neither document requires that cathodic protection be newly installed at a site.605 In fact, both the NEI and EPRI documents acknowledge that cathodic protection systems may or may not be installed at a site and, accordingly, provide guidelines for a program that manages buried piping with or without cathodic protection.606 221. Mr. Holston further clarified both the NEI and EPRI documents recommend cathodic protection for situations where the risk of failure is unacceptable (NEI 09-14) or the risk of failure is unacceptably high (EPRI 1016456).607 Neither document recommends the use of cathodic protection for all critical piping systems. As discussed above, failure means a failure of a buried piping system to maintain the pressure boundary integrity, such that adequate flow and pressure cannot be deliverednot simply leakage from a piping system. Further, both the NEI and EPRI guidance recognize that the absence of cathodic protection may be addressed by other means, such as risk-ranking and the selection of locations to be inspected based on the consequences of failure.608 604 See NEI 09-14, Rev. 1, Guideline for the Management of Underground Piping and Tank Integrity, Section 6.2.3 (Dec. 2010) (NEI 09-14, Rev. 1) (NYS000168); EPRI 1016456, at Sections 2.4.1.2, A.2.6 (Dec. 2008)

(NYS000167). The NEI initiative requirements are summarized in Appendix B of NEI 09-14, Rev. 1, and the EPRI recommendations are summarized in Appendix A of EPRI 1016456; see also Dec. 11, 2012 Tr. at 3882:7-15 (Biagiotti) (stating that EPRI and NEI guidance aim to maintain the adequacy of already-installed cathodic protection).

605 See Dec. 11, 2012 Tr. at 3881:16-21 (Cavallo) (stating that EPRI 1016456 was developed by the Buried Pipe Information Group, and that [t]he intent of the document was never to mandate cathodic protection); id. at 3883:3-16 (Biagiotti).

606 See NEI 09-14, Rev. 1 at Section 6.2.3 (NYS000168) (Where buried pipes are protected by a cathodic protection (CP) system, the CP system shall be periodically inspected and tested to assess its continued adequacy.); EPRI 1016456 at Section 2.4.1.2 (NYS000167) (Where buried pipes are protected by a cathodic protection (CP) system, the CP system should be periodically inspected and tested to assess its continued adequacy.).

607 NRC Staff Testimony at 72 (A65) (NRCR20016).

608 See NEI 09-14, Revision 1 at 6, 7, 19-20 (NYS000168).

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222. For the above reasons, the Board rejects Dr. Duquettes argument that the BPTIP is inconsistent with industry guidance. The guidance documents on which he relies do not mandate site-wide cathodic protection and, indeed, recognize its justifiable absence at some operating nuclear power plants. Furthermore, as explained above, the Board is satisfied that Entergys continuing evaluation of potential cathodic protection needs based on newly emergent technical data and operating experience is a sound and prudent approach.

J. The BPTIP Is Consistent with the Key Recommendations Contained in NACE SP0169-2007 223. Dr. Duquette also argued that Entergy should follow the recommendations of NACE SP0169-2007.609 However, it is not clear to what recommendations Dr. Duquette is referring in his pre-filed testimony.

224. As described by Mr. Holston, NACE SP0169-2007 recognizes three preventive actions for buried components, including (1) protective coatings, and (2) use of backfill that will not damage the component coatings, and (3) cathodic protection.610 It suffices to say that the Board has thoroughly evaluated the evidence related to each of these topics and finds the BPTIP to be adequate on all three counts.

225. In brief, the evidence shows that protective coatings were installed on IP2 and IP3 buried piping during original plant construction in accordance with standard (and still accepted) 609 New York Rebuttal Testimony at 8:13-16, 12:1-2 (NYSR20399). As Mr. Holston explained, the NRC Staff does not require its licensees to satisfy industry guidelines or recommendations, unless those recommendations have been adopted as regulatory or license requirements. NRC Staff Testimony at 71 (A65) (NRCR20016).

Similarly, the Staff does not evaluate the adequacy of an applicants AMP against the recommendations of industry groups. Id. Therefore, any alleged failure by Entergy to comply with NACE guidelineswhich have not been adopted by the NRC as requirements requirementsis not ipso facto a violation of 10 C.F.R. Part 54.

610 NRC Staff Testimony at 34-37 (A29) (NRCR20016).

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industry practices, and that coatings will continue to be reapplied per Entergy procedures when repair or replacement of coatings proves necessary based upon inspection activities.611 226. With regard to backfill quality, NACE SP0169-2007, Section 5.2.3.6, states that, Care should be taken during backfilling so that rocks and debris do not strike and damage the pipe coating.612 The current Staff position, as reflected in NUREG-1801, Rev. 2, AMP XI.M41, is that backfill quality may be verified by examining the backfill while conducting the inspections.613 Given that Entergy previously has identified and attributed some coating damage to rocks in the original backfill, it has increased the numbers of direct visual inspections of excavated piping to gain an adequate understanding of the extent to which deleterious materials in its backfill may have damaged protective coatings.614 Insofar as Entergy discovers unacceptable backfill quality during these inspections, it must take appropriate corrective actions.615 227. Finally, Entergys approach to cathodic protection is consistent with accepted industry practices, including those set forth in NACE SP0169-2007.616 Specifically, Entergy is risk-ranking, screening (through indirect inspection techniques-APEC and guided wave testing),

and visually inspecting (through excavation) buried piping to detect coating degradation and then installing targeted cathodic protection systems as warranted by the inspection data.617 These 611 Id. at 35 (A29).

612 Id. (citing NACE SP0169-2007 at Section 5.2.3.6 (ENT000388)).

613 Id. at 36 (A29).

614 Id.

615 Dec. 11, 2012 Tr. at 3839:14-24 (Ivy) (discussing Attach. 7.3, Pipe/Tank Base Metal Visual Inspection Checklist on page 15 of EN-EP-S-002-MULTI, Rev. 1 (ENT000600)); id. at 3948:20-25 (Azevedo).

616 NRC Staff Testimony at 34 (A29) (NRCR20016) ([T]he Indian Point LRA . . . has addressed the three preventative actions discussed in NACE SP0169-2007 (cathodic protection, protective coatings, and backfill quality).).

617 Entergy Testimony at 119-20 (A133) (ENTR30373).

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actions provide reasonable assurance that the effects of aging on in-scope buried components will be adequately managed during the PEO.

V.

SUMMARY

FINDINGS OF FACT AND CONCLUSIONS OF LAW 228. Based upon a review of the entire record of this proceeding and the parties proposed findings of fact and conclusions of law, and based upon the findings set forth above, which are supported by reliable, probative, and substantive evidence in the record, the Board has decided all matters in controversy in NYS-5 in favor of Entergy and the NRC Staff.

229. The Board finds that Entergy has carried its burden of proof to demonstrate that its AMP for buried piping and tanks within the scope of license renewal, the BPTIP, provides reasonable assurance that Entergy will adequately manage the effects of aging on those buried components, including those that may contain radioactive fluids, during the PEO.

230. In particular, with respect to New Yorks contention that the LRA does not provide an adequate AMP for buried pipes or tanks that contain radioactive fluids, we find that the overwhelming preponderance of the evidence demonstrates that:

a. The BPTIP is consistent with the applicable recommendations in NUREG-1801 (Revisions 1 and 2) and the NRC Staffs Final LR-ISG-2011-03. Specifically, the BPTIP includes the key elements of NUREG-1801 AMP XI.M41, as revised by Final LR-ISG-2011-03 (e.g., number of inspections, soil sampling, and use of plant specific operating experience).

Entergy has committed to perform a total of ninety-four (94) excavated direct visual inspections of in-scope buried piping before and during the IP2 and IP3 periods of extended operation for IP2 and IP3. It also has committed to conduct appropriate soil sampling and testing to further evaluate soil conditions before and during PEO. The additional soil sampling and augmented buried piping inspections to which Entergy has committed constitute an acceptable alternative to installing site-wide cathodic protection on all in-scope buried piping systems. These

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commitments provide reasonable assurance that Entergy will adequately manage the effects of aging on in-scope buried components during the PEO.

b. The essential elements of the BPTIP, including preventive measures to mitigate corrosion, risk ranking, trending of inspection results, the number and frequency of inspections, and the quantity and frequency of soil tests have been appropriately documented in LRA Sections A.2.1.5 and A.3.1.5 (the UFSAR Supplements), LRA Section B.1.6, Entergy Commitment Nos. 3 and 48), and SER Supplement 1.618

c. Changes to procedures described in the UFSAR can be made only in accordance with 10 C.F.R. § 50.59. Thus, before modifying its procedures, Entergy must conduct rigorous internal reviews to determine whether the proposed changes would materially affect license renewal commitments in the IPEC UFSAR Supplements or other licensing basis documents.

Those reviews are subject to the NRCs regulatory oversight and enforcement processes.

d. Entergy is not relying on unenforceable commitments and procedures. Entergys commitments are documented in SER Supplement 1. Such commitments, in turn, must be incorporated into the FSAR in accordance with 10 C.F.R. §§ 50.59 and 50.71(e) and will become part of the plants licensing basis.619 Moreover, Entergy has incorporated explicit references to its license renewal commitments in its corporate procedures to ensure that that any procedure changes are appropriately reviewed in accordance with Entergys PAD procedure and, as necessary, 10 C.F.R. § 50.59.

618 Dec. 11, 2012 Tr. at 3641:21-36425 (Holston).

619 Entergy Testimony at 81-82 (A100-01) (ENTR30373); Dec. 11, 2012 Tr. at 3641:6-20 (Green) (So the inclusion of those commitments in Appendix A to our [SER] would then make it part of the Applicants current licensing basis.).

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e. Entergy has fully identified those IP1, IP2, and IP3 systems containing buried and underground piping that support systems performing license renewal intended functions, including those systems that contain or may contain radioactive fluids.

f. The BPTIP is intended to manage material loss due to external corrosion of buried piping and tanks to provide reasonable assurance that the associated systems can perform their intended functions. The intended safety function of buried components managed under the BPTIP is to maintain a pressure boundarynot to contain fluids as suggested by New York or prevent all inadvertent leaks irrespective of their effect on the pipings intended safety function.

g. Entergy has provided sufficient details concerning the number and timing of buried and underground piping inspections, the inspection prioritization process, inspection methods, acceptance criteria, and corrective actions to meet the requirements of 10 C.F.R. Part

54. Any coating or piping degradation detected during buried piping inspections will be entered into the IPEC Corrective Action Program and evaluated for extent of condition in accordance with 10 C.F.R. Part 50 requirements and Entergys corrective action procedures.

h. Entergy has a sufficiently detailed understanding of the condition of IPEC buried pipes and their coatings through direct visual examinations of excavated piping and indirect (e.g.,

APEC, guided-wave testing) inspections performed to date. These insights also are based on the results of field surveys of underground structures and other information, including soil resistivity tests.620 The available data do not indicate that degradation of in-scope buried piping or its coatings is widespread at IPEC.

i. Contrary to New Yorks claims, Entergys soil testing data and site area corrosion potential mapping do not indicate the presence of aggressive (i.e., corrosive) soils.

620 Entergy Testimony at 66 (A86), 100-03 (A119) (ENTR30373).

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Further, Entergy has committed to perform additional soil sampling and testing to confirm that the soil conditions in the vicinity of in-scope buried pipes remain non-aggressive.

j. Entergy has acted consistent with NRC and industry guidance documents (which do not mandate the installation of site-wide cathodic protection), its own procedures, and vendor recommendations relative to the use of cathodic protection. As part of current operations, Entergy has undertaken preventive maintenance of existing IPEC cathodic protection systems and, based on vendor recommendations, installed several new cathodic protection systems for corrosion control on buried piping that is within the scope of the BPTIP.

Entergy continues to evaluate the need for further cathodic protection based on inspection results and operating experience and install additional cathodic protection systems where prudent for corrosion control.

k. The NRC has not adopted NACE SP0169-2007 recommendations as regulatory requirements. Nonetheless, Entergy has addressed the three major preventive actions discussed in NACE SP0169-2007 (cathodic protection, protective coatings, and backfill quality), and has correspondingly increased the number of excavated direct visual inspections of buried piping due to the lack of site-wide cathodic protection at IPEC and plant-specific operating experience.

231. In summary, we have reviewed all the issues, motions, and arguments presented for this contention and conclude that the preponderance of the evidence shows that the BPTIP provides reasonable assurance that in-scope buried components, including those that may contain radioactive fluids, will perform their intended functions during the PEO. The Board thus finds that Entergy has carried its burden of proof and, based on the entire record of this proceeding, resolves Contention NYS-5 in Entergys favor. Issues, motions, and arguments presented by the parties but not addressed herein have been found to be without merit, unnecessary, or not relevant to the Boards findings on NYS-5.

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VI. ORDER WHEREFORE, IT IS ORDERED, pursuant to 10 C.F.R. §§ 2.1210, that Contention NYS-5 is resolved on the merits in favor of Entergy.

IT IS FURTHER ORDERED, this Partial Initial Decision will constitute a final decision of the Commission forty (40) days from the date of issuance (or the first agency business day following that date if it is a Saturday, Sunday, or federal holiday, see 10 C.F.R. § 2.306(a)),

unless a petition for review is filed in accordance with 10 C.F.R. § 2.1212, or the Commission directs otherwise.

IT IS FURTHER ORDERED that any party wishing to file a petition for review on the grounds specified in 10 C.F.R. § 2.341(b)(1) must do so within twenty-five (25) days after service of this Partial Initial Decision. The filing of a petition for review is mandatory for a party to have exhausted its administrative remedies before seeking judicial review. Within twenty-five (25) days after service of a petition for review, parties to the proceeding may file an answer supporting or opposing Commission review. Any petition for review and any answer shall conform to the requirements of 10 C.F.R. § 2.341(b)(2)-(3).

Although this ruling resolves all matters before the Board in connection with Contention NYS-5, NRC Staff issuance of the renewed operating licenses under 10 C.F.R. Part 54 must abide by, among other things, the resolution of admitted contentions NYS-25, NYS-26B/RK-TC-1B, RK-EC-8, and NYS-38/RK-TC-5.

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Respectfully submitted, Executed in Accord with 10 C.F.R. § 2.304(d)

William B. Glew, Jr., Esq. Kathryn M. Sutton, Esq.

William C. Dennis, Esq. Paul M. Bessette, Esq.

ENTERGY SERVICES, INC. MORGAN, LEWIS & BOCKIUS LLP 440 Hamilton Avenue 1111 Pennsylvania Avenue, NW White Plains, NY 10601 Washington, DC 20004 Phone: (914) 272-3202 Phone: (202) 739-3000 Fax: (914) 272-3205 Fax: (202) 739-3001 E-mail: wglew@entergy.com E-mail: ksutton@morganlewis.com E-mail: wdennis@entergy.com E-mail: pbessette@morganlewis.com Martin J. ONeill, Esq.

MORGAN, LEWIS & BOCKIUS LLP 1000 Louisiana Street, Suite 4000 Houston, TX 77002 Phone: (713) 890-5710 Fax: (713) 890-5001 E-mail: martin.oneill@morganlewis.com COUNSEL FOR ENTERGY NUCLEAR OPERATIONS, INC.

Dated in Washington, D.C.

this 22nd day of March 2013

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UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of ) Docket Nos. 50-247-LR and

) 50-286-LR ENTERGY NUCLEAR OPERATIONS, INC. )

)

(Indian Point Nuclear Generating Units 2 and 3) )

) March 22, 2013 CERTIFICATE OF SERVICE Pursuant to 10 C.F.R. § 2.305 (as revised), I certify that, on this date, copies of Entergys Proposed Findings of Fact and Conclusions of Law For Contention NYS-5 (Buried Piping) were served upon the Electronic Information Exchange (the NRCs E-Filing System), in the above-captioned proceeding.

Signed (electronically) by Lance A. Escher Lance A. Escher, Esq.

MORGAN, LEWIS & BOCKIUS LLP 1111 Pennsylvania Ave. NW Washington, DC 20004 Phone: (202) 739-5080 Fax: (202) 739-3001 E-mail: lescher@morganlewis.com COUNSEL FOR ENTERGY NUCLEAR OPERATIONS, INC.

DB1/ 73604277